Back to GetFilings.com
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
X EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________________ to __________________
Commission File Number 1-7978
BLACK HILLS POWER, INC.
(formerly known as Black Hills Corporation)
Incorporated in South Dakota IRS Identification Number 46-0111677
625 Ninth Street
Rapid City, South Dakota 57701
Registrant's telephone number, including area code
(605) 721-1700
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
YES X NO______
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. This paragraph is not applicable to the Registrant.
State the aggregate market value of the voting stock held by non-affiliates of
the Registrant.
All outstanding shares are held by the Registrant's parent company, Black Hills
Corporation.
Indicate the number of shares outstanding of each of the Registrant's classes of
common stock, as of the latest practicable date.
Class Outstanding at March 30, 2001
Common stock, $1.00 par value 23,416,396 shares
Reduced Disclosure
The Registrant meets the conditions set forth in General Instruction I (1) (a)
and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced
disclosure format.
FORWARD-LOOKING STATEMENTS
This Form 10-K includes "forward-looking statements" as defined by the
Securities and Exchange Commission. These statements concern our plans,
expectations and objectives for future operations. All statements, other than
statements of historical facts, included in this Form 10-K that address
activities, events or developments that we expect, believe or anticipate will or
may occur in the future are forward-looking statements. The words "believe,"
"plan," "intend," "anticipate," "estimate," "project" and similar expressions
are also intended to identify forward-looking statements. These forward-looking
statements include, among others, such things as:
o expansion and growth of our business and operations;
o future financial performance;
o future acquisition and development of power plants;
o future production of coal, oil and natural gas;
o reserve estimates; and
o business strategy.
These forward-looking statements are based on assumptions which we believe
are reasonable based on current expectations and projections about future events
and industry conditions and trends affecting our business. However, whether
actual results and developments will conform to our expectations and predictions
is subject to a number of risks and uncertainties which could cause actual
results to differ materially from those contained in the forward-looking
statements, including the following factors:
o prevailing governmental polices and regulatory actions with
respect to allowed rates of return, industry and rate structure,
acquisition and disposal of assets and facilities, operation and
construction of plant facilities, recovery of purchased power and
other capital investments, and present or prospective wholesale
and retail competition;
o changes in and compliance with environmental and safety laws and
policies;
o weather conditions;
o counterparty credit risk;
o population growth and demographic patterns;
o competition for retail and wholesale customers;
o pricing and transportation of commodities;
o market demand, including structural market changes;
o changes in tax rates or policies or in rates of inflation;
o changes in project costs;
o unanticipated changes in operating expenses or capital
expenditures;
o capital market conditions;
o technological advances;
o competition for new energy development opportunities; and
o legal and administrative proceedings that influence our business
and profitability.
TABLE OF CONTENTS
Page
ITEMS
1 & 2. BUSINESS AND PROPERTIES............................................4
General......................................................4
Electric Utility.............................................4
Independent Energy...........................................5
Communications...............................................5
ITEM 3. LEGAL PROCEEDINGS..................................................6
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS................................................7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS..............................................7
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK........14
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................18
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE............................43
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K...43
SIGNATURES........................................................46
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
General
We are an electric utility serving customers in South Dakota, Wyoming and
Montana. We are incorporated in South Dakota and began providing electric
utility service in 1941. We began selling and marketing various forms of energy
on an unregulated basis in 1956. Our independent energy group produces and
markets power and fuel. We produce and sell electricity in a number of markets,
with a strong emphasis on the western United States. We produce coal, natural
gas and crude oil primarily in the Rocky Mountain region and market fuel
products nationwide. Our communications group offers state-of-the-art broadband
communication services to residential and business customers in Rapid City and
the northern Black Hills region of South Dakota.
During 2000, we became a wholly-owned subsidiary of Black Hills Corporation
(formerly Black Hills Holding Corporation) through a "plan of exchange" between
us and Black Hills Corporation. The "plan of exchange" provided that each share
of our common stock would be exchanged for one share of common stock of the
holding company. As a result:
o all common shareholders of Black Hills Power, Inc. (formerly Black Hills
Corporation) became shareholders of Black Hills Corporation (formerly Black
Hills Holding Corporation), the holding company;
o Black Hills Power, Inc. became a wholly-owned subsidiary of Black Hills
Corporation; and
o The debt securities and other financial obligations of Black Hills Power,
Inc. continue to be obligations of Black Hills Power, Inc.
Unless the context otherwise requires, references in this Form 10-K to "Black
Hills Power," "we," "us" and "our" refer to Black Hills Power, Inc. and all of
its subsidiaries collectively.
Electric Utility
We engage in the generation, transmission and distribution of electricity to
approximately 58,600 customers in South Dakota, Wyoming and Montana. We control
458 megawatts of generating capacity, including 65 megawatts of capacity
purchased from others under long-term power contracts at rates which currently
are significantly lower than prevailing market prices. Approximately 53 percent
of our generating capacity consists of coal-fired plants and 33 percent is gas-
or oil-fired, with the remaining 14 percent purchased from others.
Our revenue mix for 2000 was comprised of 29 percent wholesale off-system, 26
percent commercial, 20 percent residential, 14 percent industrial, 10 percent
contract wholesale and 1 percent municipal sales. In 2000, our South Dakota
customers accounted for 92 percent of our retail electric revenues. Our retail
electric rates in South Dakota are subject to a five-year freeze expiring on
January 1, 2005. Because our generation capacity typically exceeds our peak load
demands, we rarely purchase power on the spot market during periods of peak
usage, permitting us to preserve our low-cost rate structure for our retail
customers. Off-system sales offer a means to optimize the utilization of our
power supply sources by permitting us to sell capacity and energy in excess of
our native load requirements to wholesale customers at market prices which
sometimes exceed our regulated retail rates. Wholesale off-system sales have
represented an increasing percentage of our total revenues and net income. We
added 40 megawatts of additional capacity to our system with the addition of the
Neil Simpson combustion turbine, which we placed into operation in June 2000.
We operate a transmission system of 447 miles of high voltage and 541 miles of
lower voltage lines. Our system has the capability of connecting to either the
midwestern or western transmission grids. This provides us with an important
strategic opportunity to shift off-system power to areas of higher demand and
profitability as market conditions warrant.
Independent Energy
Our independent power unit acquires, develops and operates unregulated power
plants, primarily in the Rocky Mountain region of the United States. In July
2000, we expanded our presence in the independent power business by acquiring
Indeck Capital, Inc. This acquisition and subsequent additions provide us with
varying interests in 13 operating gas-fired and hydroelectric power plants in
California, Colorado, Massachusetts and New York, of which we operate 12, as
well as minority interests in several power-related funds. We have a total
ownership interest of approximately 250 net megawatts. We are in the process of
acquiring or constructing an additional net ownership interest of approximately
470 megawatts of generation capacity, approximately 330 megawatts of which we
expect to be brought into service in 2001.
As of December 31, 2000, we had 275 million tons of low-sulfur sub-bituminous
coal reserves at our Wyodak mine located near Gillette, Wyoming. Substantially
all of our coal production is sold under long-term contracts with our electric
utility and with PacifiCorp. Our Wyodak mine will also provide coal to a 90
megawatt mine-mouth power plant which is being developed for our independent
power unit and is scheduled for completion in 2003. Our oil and gas exploration
and production unit owns and operates approximately 298 oil and gas wells, all
in Wyoming, and owns working interests in another 341 wells operated by others
located in California, Montana, North Dakota, Texas, Wyoming, Louisiana,
Oklahoma and offshore in the Gulf of Mexico. As of December 31, 2000, we had
proved reserves of 4.4 million barrels of oil and 18.4 billion cubic feet of
natural gas, with approximately 62 percent of our current production consisting
of natural gas.
Our fuel marketing and transportation unit supplies wholesale natural gas
marketing and risk management products and services primarily to customers in
the Rocky Mountain and West Coast regions of the United States. In addition,
this unit markets oil in the south and coal in the eastern and midwestern
regions of the United States. Our customers include natural gas distribution
companies, municipalities, industrial users, oil and gas producers, electric
utilities and coal mines. Our average daily marketing volumes for the twelve
months ended December 31, 2000 were approximately 860,800 million British
thermal units of natural gas, 44,300 barrels of oil and 4,400 tons of coal. Our
power marketing activities involve marketing of capacity and energy from our
existing power generation facilities.
Communications
Our communications group, known as Black Hills FiberCom, offers a full suite of
local and long distance telephone service, expanded cable television service,
cable modem Internet access and high-speed data and video services to
residential and business customers. We have completed a 210 mile inter- and
intra-city fiber optic network and currently operate nearly 600 miles of two-way
interactive hybrid fiber coaxial cable in Rapid City and the northern Black
Hills region of South Dakota. The construction of our communications network is
approximately 75 percent complete, and we expect to substantially complete
construction in 2001.
ITEM 3. LEGAL PROCEEDINGS
PacifiCorp Litigation
In August 2000, we initiated an action in the United States District Court for
the District of Wyoming against PacifiCorp relating to a coal supply agreement
between PacifiCorp and us. We believe that PacifiCorp has failed to make
complete payment to us for coal sold under the coal supply agreement and that
PacifiCorp continues to underpay its monthly coal bill by approximately $100,000
per month. We believe that PacifiCorp's actions constitute a breach of the coal
supply agreement and have asked for relief in the amount of $5 million, plus all
underpayments since the commencement of our lawsuit.
PacifiCorp subsequently brought a counterclaim against us, alleging that we had
not properly adjusted upward and downward the components which make up the coal
price under the coal supply agreement, resulting in alleged overbilling to
PacifiCorp of $35 million to $40 million over an undefined period. PacifiCorp
further alleged that if past practices continue our adjustment methodology will
result in additional overcharges of approximately $150 million through the
balance of the term of the coal supply agreement, which expires in June of 2013.
In its counterclaim, PacifiCorp seeks to cancel and terminate the contract and
to recover monetary damages as proven at trial.
Management believes that we have properly billed PacifiCorp under the terms of
the coal supply agreement and that PacifiCorp's withholding of payment
constitutes a breach of contract on their part. Although it is impossible to
predict whether we will ultimately be successful with our claim or in defending
PacifiCorp's claim or, if not successful, what the impact might be, management
believes that the disposition of this matter will not have a material adverse
effect on our consolidated results of operations or financial condition. In
addition, management believes that the pending litigation has not affected and
will not affect our other agreements with PacifiCorp.
Other Litigation
On July 14, 2000, the South Coast Air Quality Management District known as
SCAQMD sent a letter to our affiliate, now called Black Hills Ontario, L.L.C,
the operator of a 12 megawatt natural-gas fired cogeneration facility located in
Ontario, California, stating that the SCAQMD had determined, as a result of a
facility audit completed for the compliance year ended June 1, 1999, that the
facility's nitrogen oxide, or Nox, emissions were 28,958 pounds over the
facility's NOx allocation established by the SCAQMD's RECLAIM emissions trading
program. As a result, the SCAQMD indicated that it would be reducing the
facility's NOx allocation by the same number of allowances for the compliance
year subsequent to a final determination on this issue. If a final determination
is reached prior to June 30, 2001, the NOx allowances would be deducted from the
facility's allocation for the compliance year ended June 30, 2002. Black Hills
Ontario has provided documentation to the SCAQMD disputing this proposed
reduction. In addition to this proposed reduction, which could affect the
facility's compliance with RECLAIM requirements for the 2001-2002 compliance
period, Black Hills Ontario also projects that its NOx emissions for the
compliance year ended June 30, 2001 may be approximately 30,000 pounds over its
current NOx allocation. There is currently significant volatility in the price
and supply of RECLAIM NOx allowances; although the SCAQMD has proposed a
revision to its regulations to stabilize the RECLAIM market, it is unclear
whether such rules will mitigate Black Hills Ontario's potential exposure for
its projected allowance shortfall. Accordingly, no assurance can be given at
this time regarding whether RECLAIM NOx allowances will be available for
purchase to allow Black Hills Ontario to comply with RECLAIM requirements for
the year ended June 30, 2001, or, if allowances are available, as to the cost of
those allowances. Black Hills Ontario may also be subject to administrative or
civil penalties with respect to alleged violations of the SCAQMD's regulation
for the compliance year ended June 30, 1999, although no notice of such
penalties has been issued.
There are no other material legal proceedings pending, other than ordinary
routine litigation incidental to our business, to which we are a party. There
are no material legal proceedings to which an officer or director is a party or
has a material interest adverse to us or our subsidiaries. There are no material
administrative or judicial proceedings arising under environmental quality or
civil rights statutes pending or known to be contemplated by governmental
agencies to which we are or would be a party.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
All of our common stock is held by our parent company, Black Hills Corporation.
Accordingly, there is no established trading market for our common stock.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
Consolidated Results
Consolidated net income for 2000 was $52.8 million, compared to $37.1 million in
1999 and $25.8 million in 1998. This equates to a 19.0 percent, 17.1 percent and
12.5 percent return on year-end common equity in 2000, 1999 and 1998,
respectively.
We reported record earnings in 2000, primarily due to strong natural gas
marketing activity, increased fuel production, expanded power generation and
increased wholesale off-system electric utility sales. Strong results in our
independent energy business group in 2000 were partially offset by start-up
losses in our communications business. Unusual energy market conditions stemming
primarily from gas and electricity shortages in California contributed to our
strong financial performance in 2000. There was approximately a $9.0 million
contribution to 2000 earnings due to prevailing prices of gas and electricity
and unusually wide gas trading margins that may not recur in the future.
Earnings in 1999 increased over 1998 due primarily to sales growth in our
electric utility and improved results in our independent energy business group,
partially offset by expected start-up losses in our communications business.
In 1998, we recorded an $8.8 million (after tax) charge to earnings related to a
write-down of certain oil and natural gas properties. Absent this charge, our
earnings for 1998 would have been $34.6 million, and our return on year-end
common equity would have been 16.1 percent. The write-down was primarily due to
historically low crude oil prices, lower natural gas prices and a decline in
value of certain unevaluated properties.
Consolidated revenues were $1,623.8 million, $791.9 million and $679.3 million
in 2000, 1999 and 1998, respectively, representing a 105 percent increase in
2000 and a 17 percent increase in 1999.
The growth in revenues in 2000 was a result of high energy commodity prices and
increased volumes of fuel marketed, primarily as a result of extreme price
volatility in the western markets, acquisitions and growth in the independent
energy business group and increases in off-system sales by our electric utility.
Prices of natural gas marketed increased from an average of $1.97-$2.15 per
million British thermal units in 1998 and 1999 to $4.19 per million British
thermal units in 2000. Daily volumes of natural gas marketed increased 35
percent from 635,500 million British thermal units per day in 1999 to 860,800
million British thermal units in 2000.
Revenue increases in 1999 resulted primarily from the acquisitions and growth in
the fuel marketing segment of our independent energy business group and
off-system sales by our electric utility.
Revenue and net income (loss) provided by each business group as a percentage of
our total revenue and net income were as follows:
2000 1999 1998
---- ---- ----
Revenue:
Independent energy 89% 83% 81%
Electric utility 11 17 19
Communications - - -
---- ---- ----
100% 100% 100%
=== === ===
Net Income (Loss):
Independent energy 55% 31% 5%
Electric utility 70 74 96
Communications (25) (5) (1)
---- --- ---
100% 100% 100%
=== === ===
Net income from the independent energy group is expected to exceed net income
derived from utility operations in 2001. We expect that earnings growth from the
independent energy group over the next few years will be driven primarily by our
continued expansion in the independent power production segment. We also believe
that continued strength in commodity prices and energy markets will provide the
opportunity for strong results in our fuel marketing and oil and gas production
operations.
We have continued to produce modest growth in revenue and earnings from the
retail electric business over the past two years. We believe that this trend is
stable and that, absent unplanned system outages, it will continue for the next
several years due to the extension of our electric rate freeze until January 1,
2005. The share of our future earnings generated from wholesale off-system
electric sales will depend on many factors including native load growth, plant
availability and commodity prices in the western markets.
Although our communications business significantly increased residential and
business customers in 2000, we expect it will sustain approximately $10 million
in net losses in 2001, with annual losses decreasing thereafter and
profitability expected in the next three to four years.
The following business group and segment information includes intercompany
eliminations.
Electric Utility
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $173,308 $133,222 $129,236
Operating expenses 105,100 80,936 79,340
-------- -------- --------
Operating income $ 68,208 $ 52,286 $ 49,896
======== ======== ========
Net income $ 37,105 $ 27,286 $ 24,825
======== ======== ========
EBITDA $ 88,853 $ 68,299 $ 64,936
======== ======== ========
Our electric revenue increased 30.1 percent in 2000 compared to 3.1 percent in
1999. The increase in electric revenue in 2000 was primarily due to a 54 percent
increase in wholesale off-system sales at an average price that was 3.1 times
higher than the average price in 1999. The increase in off-system sales was
driven by high spot market prices for energy in 2000, which enabled us to
generate more energy from our combustion turbine facilities, including the Neil
Simpson combustion turbine which we placed into commercial operation in June
2000. Megawatthours generated from our oil-fired diesel and natural gas-fired
combustion turbines were 305,767 in 2000, 25,882 in 1999 and 33,082 in 1998.
Historically, market prices were not sufficient to support the economics of
generating from these facilities, except to meet peak demand and as standby use
for native load requirements.
Firm kilowatthour sales increased 2.8 percent in 2000 compared to a decrease of
0.1 percent in 1999. Residential and commercial sales increases of 6 percent and
3 percent, respectively, in 2000 were partially offset by a 2 percent decrease
in industrial sales, primarily due to load reductions at Homestake Gold Mine.
Degree days, a measure of weather trends, were 16 percent above 1999 and 1
percent above normal in 2000. Degree days in 1999 were 9 percent below 1998 and
13 percent below normal. The increase in electric revenue in 1999 was primarily
due to stable firm sales combined with a 20 percent increase in off-system
sales.
Revenue per kilowatthour sold was 6.4 cents in 2000, compared to 5.4 cents in
1999 and 1998. The number of customers in the service area increased to 58,601
from 57,709 in 1999 and from 56,856 in 1998. The revenue per kilowatthour sold
in 2000 reflects a 54 percent increase in wholesale non-firm sales to 684,378
megawatthours and robust wholesale power prices. The revenue per kilowatthour
sold in 1999 reflects the 20 percent increase in wholesale non-firm sales to
445,712 megawatthours. The revenue per kilowatthour sold in 1998 reflects the 33
percent increase in wholesale non-firm sales to 371,104 megawatthours.
Our electric utility operating expenses increased by 30 percent in 2000,
primarily due to increased fuel, purchased power, and operating and maintenance
expenses, partially offset by lower depreciation. Fuel expense in 2000 included
the cost associated with the additional combustion turbine generation. Operating
expenses increased 2.0 percent in 1999, primarily due to increased purchase
power expense, operations and maintenance expenses and depreciation, partially
offset by lower fuel expense.
We forecast firm energy sales in our retail service territory to increase over
the next 10 years at an annual compound growth rate of approximately 1 percent,
with the system demand forecasted to increase at a rate of 2 percent. We
currently have a winter peak of 344 megawatts established in December 1998 and a
summer peak of 372 megawatts established in August 2000. These forecasts are
derived from studies conducted by us whereby we examined and analyzed our
service territory to estimate changes in the needs for electrical energy and
demand over a 20-year period. These forecasts are only estimates, and the actual
changes in electric sales may be substantially different. Weather deviations can
also affect energy sales significantly when compared to forecasts based on
normal weather.
Independent Energy
2000 1999 1998
---- ---- ----
(in thousands)
Revenue:
Fuel marketing $1,353,795 $614,228 $506,043
Coal production 30,530 31,095 31,413
Oil and gas production 19,183 13,052 12,562
Independent power 39,331 - -
---------- -------- --------
Total revenue 1,442,839 658,375 550,018
Expenses 1,381,991 644,196 536,048*
---------- -------- --------
Operating income $ 60,848 $ 14,179 $ 13,970*
========== ======== ========
Net income $ 28,946 $ 11,882 $ 10,068*
========== ======== ========
EBITDA** $ 65,184 $ 25,016 $ 22,530
========== ======== ========
- ---------------
* Excludes $13.5 million pre-tax, $8.8 million after tax, non-cash write-down
relating to oil and gas properties due to historically low crude oil prices,
lower natural gas prices and a decline in the value of unevaluated
properties.
** EBITDA represents earnings before interest, income taxes, depreciation and
amortization and any non-recurring or non-cash items. EBITDA is used by
management and some investors as an indicator of a company's historical
ability to service debt. Management believes that an increase in EBITDA is
an indicator of improved ability to service existing debt, to sustain
potential future increases in debt and to satisfy capital requirements.
However, EBITDA is not intended to represent cash flows for the period, nor
has it been presented as an alternative to either operating income, as
determined by generally accepted accounting principles, or as an indicator
of operating performance or cash flows from operating, investing and
financing activities, as determined by generally accepted accounting
principles, and is thus susceptible to varying calculations. EBITDA as
presented may not be comparable to other similarly titled measures of other
companies.
The following is a summary of coal, oil and natural gas production:
2000 1999 1998
---- ---- ----
Tons of coal sold 3,050,000 3,180,000 3,280,000
Barrels of oil sold 334,000 318,000 344,000
Mcf of natural gas sold 3,274,000 2,791,000 2,056,000
Mcf equivalent sales 5,278,000 4,698,000 4,120,000
The following is a summary of average daily fuel marketing volumes:
2000 1999 1998
---- ---- ----
Natural gas - MMBtus 860,800 635,500 524,800
Crude oil - barrels 44,300 19,270 19,000
Coal - tons 4,400 4,500 4,400*
- ------------
* Since the acquisition date
The independent energy business group's revenues increased 119 percent in 2000
and 20 percent in 1999. The revenue increase in 2000 was a direct result of gas
and electricity shortages in the West Coast markets and the closing of the
Indeck Capital acquisition. The revenue increase in 1999 was primarily the
result of consolidating our three fuel marketing companies' operations from the
time of their acquisitions. Additionally, revenues increased in both years as a
result of increased volumes and increased fuel and power prices. Daily volumes
of natural gas marketed increased 35 percent in 2000 and 21 percent in 1999. The
July 2000 acquisition of Indeck Capital contributed to our strong earnings
growth in 2000. In addition, in December 2000, we sold our ownership interest in
a power fund management company which resulted in a $3.7 million pre-tax gain.
The independent energy business group's total operating expenses, EBITDA and
operating income increased over 115 percent, 160 percent and 329 percent,
respectively, in 2000 compared to 1999. Net income of this group increased 144
percent in 2000. These increases resulted primarily from our gas marketing
operations, which experienced a dramatic increase in both trading volumes and
margins, a significant increase in fuel production volumes, record fuel and
power prices and expanded power generation. The independent energy business
group's 1999 net income improved over 1998 (excluding the non-cash charge in
1998) primarily due to record gas production, improved oil prices, lower
depletion expense and the sale of certain retail gas marketing operations in
1999, partially offset by a non-cash write-down of certain intangible assets
relating to our wholesale gas marketing office in Houston.
Coal Mining
Coal mining results were as follows:
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $30,530 $31,095 $31,413
Operating income 8,800 12,600 12,700
Net income 7,200 9,700 9,750
EBITDA 19,000 15,700 15,600
A planned five-week overhaul at the Wyodak plant resulted in lower coal sales
and earnings in 2000 compared to 1999 and 1998.
Oil and Gas
Oil and gas operating results were as follows:
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $19,183 $13,052 $ 12,562
Operating income 7,900 4,000 1,200*
Net income 5,000 2,500 800*
EBITDA 11,900 6,900 6,400
- ------------
*Excludes $13.5 million pre-tax, $8.8 million after tax, non-cash write-down
relating to oil and gas properties due to historically low crude oil prices,
lower natural gas prices and a decline in the value of unevaluated properties.
Record net income in 2000 was primarily a result of record natural gas prices,
higher crude oil prices and a significant increase in production volumes.
Operating results for 1998 decreased primarily as a result of historically low
crude oil prices, which not only reduced revenue but also increased depletion
expense (lower oil and gas prices reduce the economically recoverable reserve
amounts, causing an increase in depletion expense). We recognized approximately
$3.7 million, $2.6 million and $4.9 million of depletion expense (excluding the
write-down in 1998) related to gas and oil production in 2000, 1999 and 1998,
respectively.
The following is a summary of our oil and gas reserves at December 31:
2000 1999 1998
---- ---- ----
Barrels of oil (in millions) 4.41 4.11 2.37
Bcf of natural gas 18.4 19.5 16.0
Total in Bcf equivalents 44.88 44.11 30.16
These reserves are based on reports prepared by Ralph E. Davis Associates, Inc.,
an independent consulting and engineering firm. Reserves were determined using
constant product prices at the end of the respective years. Estimates of
economically recoverable reserves and future net revenues are based on a number
of variables, which may differ from actual results. The increase in oil reserves
at December 31, 2000 was due to improved product prices. The increase in
reserves at December 31, 1999 was due to strong drilling results, reserve
acquisitions and improved product prices. We intend to increase our net proved
reserves by selectively increasing our oil and gas exploration and development
activities and by acquiring producing properties.
Fuel Marketing
Our fuel marketing companies produced the following results:
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $1,353,795 $614,228 $506,043
Operating income (loss) 23,800 (2,200) -
Net income 14,000 (200) (300)
EBITDA 23,700 2,500 600
Record volumes marketed and strong margins contributed to the increase in net
income from fuel marketing in 2000 compared to 1999 and 1998. During 1999, the
fuel marketing companies sold certain of their retail gas marketing operations,
resulting in after-tax gains of approximately $1.8 million. In 1999, revenue and
the related cost of sales increased primarily due to a full year of coal
marketing operations (acquired in September 1998), increased product prices and
increased oil volumes marketed. Operating income in 1999 was reduced by a
non-cash write-down of certain intangible assets relating to the wholesale gas
marketing office in Houston in the amount of approximately $1.2 million (after
tax).
Our fuel marketing companies generate large amounts of revenue and corresponding
expense related to buying and selling energy commodities. Fuel marketing is
extremely competitive, and margins are typically very small. The unusual energy
market conditions stemming primarily from natural gas and electricity shortages
in California contributed to the strong financial performance in 2000 and may
not recur in the future. However, we believe that the continued growth of our
fuel and power production businesses will create opportunities for us to
continue to generate strong fuel marketing operating results in future years.
Independent Power Production
Our independent power segment produced the following results:
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $39,331 $ - $ -
Operating income (loss) 20,400 (160) (160)
Net income 3,200 (110) (120)
EBITDA 10,751 (160) (160)
Results from the independent power production segment were not significant
either in 1999 or 1998. In July 2000, we completed the acquisition of Indeck
Capital, representing a significant advancement of our position in the
independent power production business. We now own 250 net megawatts in currently
operating plants. Of this 250 net megawatts, approximately 179 megawatts is
under contracts or tolling arrangements with at least one year remaining;
approximately 40 megawatts is owned through minority interests in independent
power investment funds which we do not manage, and the remainder is sold under
short-term market arrangements. An additional 470 megawatts of generating
capacity is currently under construction. We expect to sell substantially all of
this output under long-term contracts. We expect to increase revenues and
earnings in this segment beyond 2001 through future project development.
Communications
2000 1999 1998
---- ---- ----
(in thousands)
Revenue $ 7,689 $ 278 $ -
Operating expenses 20,175 4,852 1,087
--------- -------- ---------
Operating loss $(12,486) $(4,574) $ (1,087)
========= ======== =========
Net loss $(12,027) $(1,262) $ (280)
========= ======== =========
EBITDA $(13,144) $(2,626) $ (570)
========= ======== =========
In September 1998, we formed our communications business to provide
facilities-based communications services for Rapid City and the northern Black
Hills of South Dakota. We began serving communications customers in late 1999
and market our services to schools, hospitals, cities, economic development
groups, and business and residential customers. Operating losses in 2000 were
attributable to increased interest, depreciation and operating expenses.
Operating losses in 1999 were primarily due to start-up organizational costs,
increased depreciation expense and increased interest expense associated with
capital deployment.
As of December 31, 2000, we had 8,368 residential customers and 646 business
customers. Our goal is to double the number of our customers, and to attain 50
percent residential market penetration within our service territory while
serving 35 percent of all broadband business customers in that territory. If we
are unable to attract additional customers or technological advances make our
network obsolete, we could have a write-down of our assets which could be
material.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Price Risk Management
Our operations are exposed to market risk arising from changes in commodity
prices. These changes could cause fluctuations in our earnings and cash flows.
In the normal course of business, we actively manage our exposure to these
market risks by entering into various hedging transactions. Hedging transactions
involve the use of a variety of derivative financial instruments. Our risk
management policies place clear controls on these activities.
We have adopted risk management policies and procedures, approved by our board
of directors, and reviewed routinely by the audit committee of the board of
directors. Our risk management policies and procedures include, but are not
limited to, risk tolerance levels relating to authorized derivative financial
instruments, position limits, authorization of transactions and credit exposure.
Operating margins earned by wholesale gas and crude oil marketing are relatively
insensitive to commodity price fluctuations since most of the purchase and sales
contracts do not contain fixed-price provisions. Generally, prices contained in
these contracts are tied to a current spot or index price and, therefore, adjust
directionally with changes in overall market conditions. We generally attempt to
balance our fixed-price physical and financial purchase and sales commitments.
However, we may, at times, have a bias in the market, within established
guidelines, resulting from the management of our portfolio. To the extent a net
open position exists, fluctuating commodity market prices can impact our
financial position or results of operations, either favorably or unfavorably.
The net open positions are actively managed, and the impact of changing prices
on our financial condition at a point in time is not necessarily indicative of
the impact of price movements throughout the year.
Effective January 1, 1999, we adopted the provisions of Emerging Issues Task
Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management
Activities" (EITF 98-10). The resulting effect of adoption of the provisions of
EITF 98-10 was to alter our comprehensive method of accounting for
energy-related contracts, as defined in that statement.
We account for all energy trading activities at fair value as of the balance
sheet date and recognize currently the net gains or losses resulting from the
revaluation of these contracts to fair value in our results of operations. As a
result, substantially all of the energy trading activities of our gas marketing,
crude oil marketing and coal marketing operations are accounted for under fair
value accounting methodology as prescribed in EITF 98-10.
Through our independent energy business group, we utilize financial instruments
for our fuel marketing services. These financial instruments include
fixed-for-float swap financial instruments, basis swap financial instruments,
and costless collars traded in the over-the-counter financial markets.
The derivatives are not held for speculative purposes but rather serve to hedge
our exposure related to commodity purchases or sales commitments. Under EITF
98-10, these transactions qualify as energy trading activities that must be
accounted for at fair value. As such, realized and unrealized gains and losses
are recorded as a component of income. Because we do not speculate with "open"
positions, substantially all of our trading activities are back-to-back
positions where a commitment to buy/(sell) a commodity is matched with a
committed sale/(buy) or financial instrument. The quantities and maximum terms
of derivative financial instruments held for trading purposes at December 31,
2000 and 1999 are as follows:
Max. Term
December 31, 2000 Volume Covered (Years)
- ----------------- -------------- ---------
(MMBtus)
Natural gas basis swaps purchased 25,577,894 2
Natural gas basis swaps sold 26,059,621 2
Natural gas fixed-for-float swaps purchased 6,476,222 1
Natural gas fixed-for-float swaps sold 7,360,560 1
(Tons)
Coal tons sold 988,000 1
Coal tons purchased 896,000 1
Max. Term
December 31, 1999 Volume Covered (Years)
- ----------------- -------------- -------
(MMBtus)
Natural gas futures contracts purchased 860,000 1
Natural gas basis swaps purchased 17,741,500 4
Natural gas basis swaps sold 18,390,517 4
Natural gas fixed-for-float swaps purchased 9,490,486 1
Natural gas fixed-for-float swaps sold 10,994,521 1
Natural gas collar transactions; puts purchased, calls sold 408,500 1
Natural gas collar transactions; calls purchased, puts sold 318,500 1
As required under EITF 98-10, energy trading activities were marked to fair
value on December 31, 2000, and the gains and losses recognized in earnings. The
entries for the accompanying consolidated balance sheets and income statement
are as follows (in thousands):
Instrument Asset Liability Gain (loss)
- ---------- ----- --------- -----------
Natural gas basis swaps $13,391 $23,963 $(10,572)
Natural gas fixed-for-float swaps 24,617 27,110 (2,493)
Natural gas physical 23,391 9,427 13,964
Coal transactions 5,370 4,460 910
Crude oil transactions 1,523 1,000 523
------- ------- ---------
Totals $68,292 $65,960 $ 2,332
======= ======= =========
There were no significant differences between the fair values of derivative
assets and liabilities at December 31, 1999.
Non-trading Energy Activities
To reduce risk from fluctuations in the price of oil and natural gas, we enter
into swaps and costless collar transactions. We use these transactions to hedge
price risk from sales of our forecasted crude oil and natural gas production.
For such transactions, we utilize hedge accounting.
At December 31, 2000, we had fixed-for-float swaps for 17,000 barrels of oil per
month for the year 2001 to hedge our crude oil price risk with a fair value of
$34,000. We had fixed-for-float swaps for 10,000 barrels of oil per month for
the year 2002 to hedge our crude oil price risk with a fair value of $416,000.
We also had costless collars (purchased puts-sold calls) for 10,000 barrels of
oil per month for 2001 with a fair value of $323,000. We hedged our forecasted
2001 natural gas production with fixed-for-float swaps. We had fixed-for-float
swaps for 1,581,000 million British thermal units with a fair value of $(3.4)
million. These amounts are not reflected in our December 31, 2000 consolidated
balance sheet, but will be recorded as part of the adoption of Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," on January 1, 2001.
Financing Activities
To reduce risk from fluctuations in interest rates, we enter into interest rate
swap transactions. We use these transactions to hedge interest rate risk for
variable rate debt financing. For such transactions, we utilize hedge
accounting. At December 31, 2000, we had interest rate swaps with a notional
amount of $127.4 million, which have a maximum term of six years and a fair
value of $(7.5) million. These amounts are not reflected in our December 31,
2000 consolidated balance sheet, but will be recorded as part of the adoption of
SFAS No. 133 on January 1, 2001.
Credit Risk
In addition to the risk associated with price movements, credit risk is also
inherent in our risk management activities. Credit risk relates to the risk of
loss resulting from non-performance of contractual obligations by a
counterparty. While we have not experienced significant losses due to the credit
risk associated with these arrangements, we have off-balance sheet risk to the
extent that the counterparties to these transactions fail to perform as required
by the terms of their contracts.
Interest Rate Risk
Our exposure to market risk for changes in interest rates relates primarily to
our short-term investments and long-term debt obligations. As stated in our
policy, we are averse to principal loss and ensure the safety and preservation
of our investments by limiting default risk, market risk and reinvestment risk.
We mitigate default risk on short-term investments by investing in high credit
quality securities consisting primarily of tax-exempt federal, state and local
agency obligations, by periodically monitoring the credit rating of any
investment issuer or guarantor and by limiting the amount of exposure to any one
issuer. Our portfolio includes only securities with active secondary or resale
markets to ensure portfolio liquidity. All short-term investments mature, by
policy, in two years or less. The effect of a 100 basis point (1 percent)
increase in interest rates would not have a material effect to our results of
operations or financial condition, due to the short-term duration of the
investment portfolio.
At December 31, 2000, we had $162.2 million of outstanding floating rate debt of
which $34.8 million was not offset with interest rate swap transactions that
effectively convert the interest on that debt to a fixed rate.
The table below presents principal (or notional) amounts and related weighted
average interest rates by year of maturity for our short-term investments and
long-term debt obligations, including current maturities (in thousands).
2001 2002 2003 2004 2005 Thereafter Total
Cash equivalents
Fixed rate $ 24,913 $ - $ - $ - $ - $ - $ 24,913
Average interest rate 6.23% - - - - - 6.23%
rate
Long-term debt
Fixed rate $ 3,070 $18,065 $ 3,122 $ 2,017 $ 2,026 $130,602 $158,902
Average interest rate 9.30% 6.98% 9.31% 9.50% 9.52% 8.30% 8.22%
Variable rate $10,890 $11,919 $12,968 $14,380 $15,560 $ 96,433 $162,150
Average interest rate 8.20% 8.20% 8.19% 8.19% 8.19% 8.10% 8.14%
Total long-term debt $13,960 $29,984 $16,090 $16,397 $17,586 $227,035 $321,052
Average interest rate 8.44% 7.46% 8.41% 8.35% 8.35% 8.22% 8.18%
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants 18
Consolidated Statements of Income
for the three years ended December 31, 2000 19
Consolidated Balance Sheets as of December 31, 2000 and 1999 20
Consolidated Statements of Cash Flows
for the three years ended December 31, 2000 21
Consolidated Statements of Common Stockholder's Equity
for the three years ended December 31, 2000 22
Notes to Consolidated Financial Statements 23-42
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholder of Black Hills Power, Inc.:
We have audited the accompanying consolidated balance sheets of Black Hills
Power, Inc. (formerly Black Hills Corporation, a South Dakota corporation) and
Subsidiaries as of December 31, 2000 and 1999, and the related consolidated
statements of income, common stockholder's equity and cash flows for each of the
three years in the period ended December 31, 2000. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Black Hills Power, Inc. and
Subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
Arthur Andersen LLP
Minneapolis, Minnesota,
January 26, 2001
BLACK HILLS POWER, INC.
(formerly Black Hills Corporation)
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 2000 1999 1998
---- ---- ----
(in thousands)
Operating revenues $1,623,836 $ 791,875 $ 679,254
---------- --------- ----------
Operating expenses:
Fuel and purchased power 1,370,841 637,302 531,518
Operations and maintenance 46,054 36,463 32,701
Administrative and general 44,423 18,272 15,747
Depreciation, depletion and amortization 32,864 25,067 24,037
Oil and gas ceilings test write-down - - 13,546
Taxes, other than income taxes 14,904 12,880 12,472
---------- --------- ---------
1,509,086 729,984 630,021
---------- --------- ---------
Operating income 114,750 61,891 49,233
---------- --------- ---------
Other income (expense):
Interest expense (30,342) (15,460) (14,707)
Interest income 7,075 3,614 2,861
Other, net 2,996 876 129
---------- ---------- ---------
(20,271) (10,970) (11,717)
---------- ---------- ---------
Income before minority interest and income taxes 94,479 50,921 37,516
Minority interest (11,273) 1,935 -
Income taxes (30,358) (15,789) (11,708)
---------- ---------- ---------
Net income 52,848 37,067 25,808
Preferred stock dividends (78) - -
---------- ---------- ---------
Net income available for common stock $ 52,770 $ 37,067 $ 25,808
========== ========== =========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
BLACK HILLS POWER, INC.
(formerly Black Hills Corporation)
CONSOLIDATED BALANCE SHEETS
At December 31, 2000 1999
---- ----
(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 24,913 $ 16,482
Securities available-for-sale 2,113 7,586
Receivables (net of allowance for doubtful accounts of $3,631
and $278, respectively) -
Customers 278,434 84,331
Other 21,283 55,694
Materials, supplies and fuel 16,545 14,278
Prepaid expenses 7,428 2,828
Derivatives at market value 68,292 5,158
------------ ----------
419,008 186,357
------------ ---------
Investments 73,032 10,444
------------ ---------
Property and equipment 1,072,129 700,044
Less accumulated depreciation and depletion (277,848) (246,299)
------------ ---------
794,281 453,745
------------ ---------
Other assets:
Regulatory asset 4,134 3,944
Other, principally goodwill 38,930 14,002
------------ ---------
43,064 17,946
------------ ---------
$1,329,385 $668,492
============ =========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt $ 13,960 $ 1,330
Notes payable 211,679 97,579
Accounts payable 247,596 80,355
Accrued liabilities 49,661 26,088
Derivatives at market value 65,960 5,158
------------ -----------
588,856 210,510
------------ ----------
Long-term debt, net of current maturities 307,092 160,700
------------ ----------
Deferred credits and other liabilities:
Investment tax credits 2,530 3,022
Federal income taxes 62,679 47,668
Reclamation and regulatory liability 22,340 22,494
Other 16,516 7,492
------------ ----------
104,065 80,676
------------ ----------
Minority interest in subsidiaries 37,961 -
------------ ----------
Commitments and contingencies (Notes 10, 11 and 14)
Common stock equity:
Common stock $1 par value; 50,000,000 shares authorized;
Issued: 23,416,396 shares in 2000 and 21,739,030 shares in 1999 23,416 21,739
Additional paid-in capital 77,326 40,658
Retained earnings 191,482 162,239
Treasury stock - (8,030)
Accumulated other comprehensive income (loss) (813) -
------------ ----------
291,411 216,606
------------ ----------
$1,329,385 $668,492
============ ==========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
BLACK HILLS POWER, INC.
(formerly Black Hills Corporation)
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2000 1999 1998
---- ---- ----
(in thousands)
Operating activities:
Net income available for common stock $52,770 $37,067 $25,808
Principal non-cash items-
Depreciation, depletion and amortization 32,864 25,067 24,037
Oil and gas ceilings test write-down - - 13,546
Derivative fair value adjustment, net (2,332) - -
Gain on sales of assets (3,736) (2,541) -
Deferred income taxes and investment tax credits 1,937 2,291 (2,535)
Minority interest 11,273 (1,935) -
Change in operating assets and liabilities-
Accounts receivable (201,307) 2,232 (46,821)
Materials, supplies, fuel and other current assets (3,513) (4,003) (2,954)
Accounts payable 165,394 6,268 41,465
Accrued liabilities 18,678 4,013 2,244
Other, net 2,444 5,284 (60)
---------- --------- --------
74,472 73,743 54,730
---------- --------- --------
Investing activities:
Property additions (134,855) (102,290) (25,265)
Increase in investments (13,646) (52,319) (1,960)
Payment for acquisition of net assets, net of cash acquired (28,688) - -
Proceeds from sales of assets 5,500 3,463 -
Available-for-sale securities purchased - (7,870) (22,361)
Available-for-sale securities sold 4,660 22,959 13,655
---------- ---------- ---------
(167,029) (136,057) (35,931)
---------- ---------- ---------
Financing activities:
Dividends paid (23,527) (22,602) (21,737)
Treasury stock purchased (1,037) (4,949) (3,081)
Common stock issued 3,852 424 273
Increase in short-term borrowings 73,848 92,489 5,067
Long-term debt - issuance 60,082 - -
Long-term debt - repayments (1,330) (1,330) (1,331)
Subsidiary distributions to minority interests (10,900) - -
---------- ---------- ---------
100,988 64,032 (20,809)
---------- ---------- ---------
Increase (decrease) in cash and cash equivalents 8,431 1,718 (2,010)
Cash and cash equivalents:
Beginning of year 16,482 14,764 16,774
---------- --------- ---------
End of year $ 24,913 $ 16,482 $ 14,764
========== ========= =========
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest $31,309 $18,819 $14,742
Income taxes $18,518 $13,173 $13,135
Non-cash net assets acquired through issuance of common
and preferred stock (Note 14) $34,493 $ - $ -
Non-cash exchange of treasury stock and preferred stock
for common stock (Note 1) $13,067 $ - $ -
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
BLACK HILLS POWER, INC.
(formerly Black Hills Corporation)
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated
Common Stock Additional Treasury Stock Other
---------------------- Paid-In Retained ------------------ Comprehensive
Shares Amount Capital Earnings Shares Amount Income (loss) Total
------ ------ ------- -------- ------ ------ ------------- -----
(in thousands)
Balance at
December 31, 1997 21,705 $ 21,705 $ 39,995 $ 143,703 - $ - $ - $205,403
-------- -------- ---------- ---------- --------- ---------- ---------- --------
Comprehensive Income:
Net income - - - 25,808 - - - 25,808
-------- -------- ---------- ---------- --------- ---------- ---------- --------
- - - 25,808 - - - 25,808
Dividends on common stock - - - (21,737) - - - (21,737)
Issuance of common stock 14 14 259 - - - - 273
Treasury stock acquired, net - - - - (141) (3,081) - (3,081)
-------- -------- ---------- ---------- -------- --------- ---------- --------
Balance at
December 31, 1998 21,719 21,719 40,254 147,774 (141) (3,081) - $206,666
-------- -------- ---------- ---------- -------- --------- ---------- --------
Comprehensive Income:
Net income - - - 37,067 - - - 37,067
-------- -------- ---------- ---------- -------- --------- ---------- --------
- - - 37,067 - - - 37,067
Dividends on common stock - - - (22,602) - - - (22,602)
Issuance of common stock 20 20 404 - - - - 424
Treasury stock acquired, net - - - - (227) (4,949) - (4,949)
-------- -------- ---------- ---------- -------- --------- ---------- --------
Balance at
December 31, 1999 21,739 21,739 40,658 162,239 (368) (8,030) - $216,606
-------- -------- ---------- ---------- -------- --------- ---------- --------
Comprehensive Income:
Net income - - - 52,848 - - - 52,848
Unrealized loss on available
for sale securities - - - - - - (813) (813)
-------- -------- ---------- ----------- -------- --------- ---------- --------
- - - 52,848 - - (813) 52,035
Dividends on preferred stock - - - (78) - - - (78)
Dividends on common stock - - - (23,527) - - - (23,527)
Issuance of common stock 140 140 4,428 - - - - 4,568
Issuance of common stock
for acquisition 1,537 1,537 32,240 - - - - 33,777
Treasury stock acquired, net - - - - 368 8,030 - 8,030
-------- -------- ---------- ----------- -------- --------- ---------- --------
Balance at
December 31, 2000 23,416 $ 23,416 $ 77,326 $ 191,482 - $ - $ (813) $291,411
====== ======== ========== =========== ======== ========= ========== ========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2000, 1999 and 1998
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Power, Inc. and its subsidiaries (the Company) operate in three
primary operating groups: regulated electric utility, non-regulated independent
energy and communications. Black Hills Power operates the public utility
operations. The Company operates its independent energy businesses through its
direct and indirect subsidiaries: Wyodak Resources related to coal, Black Hills
Exploration and Production related to oil and natural gas, Enserco Energy, Black
Hills Energy Resources and Black Hills Coal Network related to fuel marketing of
natural gas, oil and coal, respectively, and Black Hills Energy Capital and its
subsidiaries and Black Hills Generation related to independent power activities,
all consolidated for reporting purposes as Black Hills Energy Ventures; and
operates its communications operations through its indirect subsidiaries Black
Hills Fiber Systems, Black Hills FiberCom and Daksoft. For further descriptions
of the Company's business segments see Note 13.
During 2000, the Company became a wholly-owned subsidiary of Black Hills
Corporation (formerly Black Hills Holding Corporation) through a "plan of
exchange" between the Company and Black Hills Corporation. The "plan of
exchange" provided that each share of the Company's common stock would be
exchanged for one share of common stock of the holding company. As a result:
o all common shareholders of Black Hills Power, Inc. (formerly Black Hills
Corporation) became shareholders of Black Hills Corporation (formerly Black
Hills Holding Corporation), the holding company;
o Black Hills Power, Inc. became a wholly-owned subsidiary of Black Hills
Corporation;
o The debt securities and other financial obligations of Black Hills Power,
Inc. continue to be obligations of Black Hills Power, Inc.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and
its wholly-owned and majority-owned subsidiaries. Generally, the Company uses
equity accounting for investments of which it owns between 20 and 50 percent and
investments in partnerships under 20 percent if the Company exercises
significant influence.
All significant intercompany balances and transactions have been eliminated in
consolidation except for revenues and expenses associated with intercompany coal
sales in accordance with the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." Total intercompany coal sales not eliminated were $9.7 million,
$7.7 million and $10.3 million in 2000, 1999 and 1998, respectively.
The Company owns 51 percent of the voting securities of Black Hills FiberCom,
LLC (FiberCom). During 2000 FiberCom's operating losses reduced its members'
equity below zero. At that point the Company began to recognize 100 percent of
FiberCom's operating losses and will continue to do so until such time as
additional equity investments are made by third parties or future net income
restores members' equity to a positive amount.
As noted in Note 14, Black Hills Energy Capital made several acquisitions during
2000. The Company's consolidated statements of income include operating activity
of these companies beginning with their acquisition date.
The Company uses the proportionate consolidation method to account for its
working interests in oil and gas properties.
Minority Interest in Subsidiaries
Minority interest in results of operations of consolidated subsidiaries
represents the minority shareholders' share of the income or loss of various
consolidated subsidiaries. The minority interest in the consolidated balance
sheets reflect the amount of the underlying net assets of various consolidated
subsidiaries attributable to the minority shareholders.
Regulatory Accounting
The Company's regulated electric operations are subject to regulation by various
state and federal agencies. The accounting policies followed are generally
subject to the Uniform System of Accounts of the Federal Energy Regulatory
Commission (FERC). These accounting policies differ in some respects from those
used by the Company's non-regulated businesses.
The Company's electric operations follow the provisions of SFAS No. 71, and its
financial statements reflect the effects of the different ratemaking principles
followed by the various jurisdictions regulating its electric operations. As a
result of the Company's 1995 rate case settlement, a 50-year depreciable life
for Neil Simpson II is used for financial reporting purposes. If the Company
were not following SFAS 71, a 35 to 40 year life would be more appropriate,
which would increase depreciation expense by approximately $0.6 million per
year. If rate recovery of generation-related costs becomes unlikely or
uncertain, due to competition or regulatory action, these accounting standards
may no longer apply to the Company's regulated generation operations. In the
event the Company determines that it no longer meets the criteria for following
SFAS 71, the accounting impact to the Company would be an extraordinary non-cash
charge to operations of an amount that could be material. Criteria that give
rise to the discontinuance of SFAS 71 include increasing competition that could
restrict the Company's ability to establish prices to recover specific costs and
a significant change in the manner in which rates are set by regulators from
cost-based regulation to another form of regulation. The Company periodically
reviews these criteria to ensure the continuing application of SFAS 71 is
appropriate.
Cash Equivalents
The Company considers all highly liquid investments with an original maturity of
three months or less to be cash equivalents.
Available-for-sale Securities
The Company has investments in marketable securities that are classified as
available-for-sale securities and are carried at fair value in accordance with
the provisions of SFAS No. 115 "Accounting for Certain Investments in Debt and
Equity Securities." The unrealized gain or loss resulting from the difference
between the securities' fair value and cost basis is included as a component of
accumulated other comprehensive income in common stockholders' equity.
Inventory
Materials, supplies and fuel are stated at the lower of cost or market on a
first-in, first-out basis.
Property, Plant and Equipment
The components of property, plant and equipment are as follows, at December 31:
2000 1999
(in thousands)
Independent energy $ 430,979 $ 125,371
Electric utility 530,529 523,461
Communications 110,486 50,621
Other 135 591
---------- ---------
$1,072,129 $ 700,044
========== =========
Additions to property, plant and equipment are recorded at cost when placed in
service. Included in the cost of regulated construction projects is an allowance
for funds used during construction (AFUDC) which represents the approximate
composite cost of borrowed funds and a return on capital used to finance the
project. The AFUDC was computed at an annual composite rate of 9.7, 8.3 and 10.1
percent during 2000, 1999 and 1998, respectively. In addition, the Company
capitalizes interest, when applicable, on certain non-regulated construction
projects. The amount of AFUDC and interest capitalized was $2.0 million, $1.2
million and $0.2 million in 2000, 1999 and 1998, respectively. The cost of
regulated electric property, plant and equipment retired, or otherwise disposed
of in the ordinary course of business, together with removal cost less salvage,
is charged to accumulated depreciation. Retirement or disposal of all other
assets, except for oil and gas properties as described below, result in gains or
losses recognized as a component of income. Repairs and maintenance of property
are charged to operations as incurred.
Depreciation provisions for regulated electric property, plant and equipment is
computed on a straight-line basis using an annual composite rate of 2.8 percent
in 2000, 3.1 percent in 1999 and 3.0 percent in 1998. Non-regulated property,
plant and equipment is depreciated on a straight-line basis using estimated
useful lives ranging from 3 to 39 years. Depletion of coal, oil and gas
properties is computed using the cost method.
The Company periodically evaluates assets under SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of,"
which requires that such assets be probable of future recovery at each balance
sheet date. As of December 31, 2000 and 1999, no significant write-downs were
required.
Goodwill and Intangible Assets
Goodwill represents the excess of acquisition costs over the fair market value
of the net assets of acquired businesses and is being amortized on a
straight-line basis over the estimated useful lives of such assets, which range
from 8 to 25 years. The cost of other acquired intangibles is amortized on a
straight-line basis over their estimated useful lives. Amortization expense was
$3.1 million, $2.7 million and $0.7 million in 2000, 1999 and 1998,
respectively. Accumulated amortization was $6.7 million, $3.6 million and $0.9
million at December 31, 2000, 1999 and 1998, respectively.
Income Taxes
The Company uses the liability method in accounting for income taxes. Under the
liability method, deferred income taxes are recognized, at currently enacted
income tax rates, to reflect the tax effect of temporary differences between the
financial and tax basis of assets and liabilities. Such temporary differences
are the result of provisions in the income tax law that either require or permit
certain items to be reported on the income tax return in a different period than
they are reported in the financial statements. To the extent such income taxes
are recoverable or payable through future rates, regulatory assets and
liabilities have been recorded in the accompanying consolidated balance sheets.
Deferred taxes are provided on all significant temporary differences,
principally depreciation and depletion. Investment tax credits have been
deferred in the electric operation and the accumulated balance is amortized as a
reduction of income tax expense over the useful lives of the related electric
property which gave rise to the credits.
Revenue Recognition
Generally, revenue is recognized at the time products and services are
delivered. Fuel marketing businesses also use the mark-to-market method of
accounting. Under that method all energy trading activities are recorded at fair
value as of the balance sheet date and net gains or losses resulting from the
revaluation of these contracts to fair value are recognized currently in the
results of operations. In the fourth quarter of 2000, the Company adopted
Securities and Exchange Commission Staff Accounting Bulletin No. 101, "Revenue
Recognition" (SAB 101), which provides guidance on the recognition, presentation
and disclosure of revenue in financial statements. The adoption of SAB 101 did
not have a material impact on the financial statements.
Oil and Gas Operations
The Company accounts for its oil and gas activities under the full cost method.
Under the full cost method, all productive and nonproductive costs related to
acquisition, exploration and development drilling activities are capitalized.
These costs are amortized using a unit-of-production method based on volumes
produced and proved reserves. Any conveyances of properties, including gains or
losses on abandonments of properties, are treated as adjustments to the cost of
the properties with no gain or loss recognized. Under the full cost method, net
capitalized costs may not exceed the present value of proved reserves.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Ultimate results could differ from those estimates.
Reclassifications
Certain 1999 and 1998 amounts in the financial statements have been reclassified
to conform to the 2000 presentation. These reclassifications had no effect on
the Company's common stockholder's equity or results of operations, as
previously reported.
Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No.
133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities."
SFAS 133, as amended, establishes accounting and reporting standards requiring
that every derivative instrument be recorded in the balance sheet as either an
asset or liability measured at its fair value. The Statement requires that
changes in the derivative instrument's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met.
SFAS 133 allows special hedge accounting for fair value and cash flow hedges.
The Statement provides that the gain or loss on a derivative instrument
designated and qualifying as a fair value hedging instrument as well as the
offsetting loss or gain on the hedged item attributable to the hedged risk be
recognized currently in earnings in the same accounting period. SFAS 133
provides that the effective portion of the gain or loss on a derivative
instrument designated and qualifying as a cash flow hedging instrument be
reported as a component of other comprehensive income and be reclassified into
earnings in the same period or periods during which the hedged forecasted
transaction affects earnings. The remaining gain or loss on the derivative
instrument, if any, must be recognized currently in earnings.
SFAS 133 requires that on date of initial adoption, an entity shall recognize
all freestanding derivative instruments in the balance sheet as either assets or
liabilities and measure them at fair value. The difference between a
derivative's previous carrying amount and its fair value shall be reported as a
transition adjustment. The transition adjustment resulting from adopting this
Statement shall be reported in net income or other comprehensive income, as
appropriate, as the effect of a change in accounting principle in accordance
with paragraph 20 of Accounting Principles Board Opinion No. 20 (APB 20),
"Accounting Changes."
Upon adoption of SFAS 133, most of the Company's energy trading activities
previously accounted for under Emerging Issues Task Force Issue No. 98-10,
"Accounting for Energy Trading and Risk Management Activities" (EITF 98-10) will
fall under the purview of SFAS 133. The effect from this adoption on the energy
trading companies and energy trading activities will not be material because,
unless otherwise noted, the trading companies will not designate their energy
trading activities as hedge instruments. This "no hedge" designation will result
in these derivatives being measured at fair value and gains and losses
recognized currently in earnings. This treatment under SFAS 133 will be
comparable to the accounting under EITF 98-10.
At December 31, 2000, the Company had certain non-trading energy contracts
documented as cash flow hedges. These contracts are defined as derivatives under
SFAS 133 and meet the requirements for cash flow hedges. Because these
non-trading energy contracts were documented as hedges prior to adoption, the
transition adjustment will be reported in accumulated other comprehensive
income. The aggregated entry for the derivatives identified as energy cash flow
hedges will increase derivative assets by $1.4 million, increase the derivative
liabilities by $4.0 million and decrease accumulated other comprehensive income
by $2.6 million.
At December 31, 2000, the Company had interest rate swaps documented as cash
flow hedges. These contracts are defined as derivatives under SFAS 133 and meet
the requirements for cash flow hedges. Because these contracts were documented
as hedges prior to adoption, the transition adjustment will be reported in
accumulated other comprehensive income. The interest rate swap transactions have
a notional amount of $127.4 million and the associated transition adjustments
will increase derivative liabilities by $7.5 million and decrease accumulated
other comprehensive income by $7.5 million.
(2) PRICE RISK MANAGEMENT
The Company is exposed to market risk stemming from changes in commodity prices.
These changes could cause fluctuations in the Company's earnings and cash flows.
In the normal course of business, the Company actively manages its exposure to
these market risks by entering into various hedging transactions, which are
authorized under its policies that place clear controls on these activities.
Hedging transactions involve the use of a variety of derivative financial
instruments.
Effective January 1, 1999, the Company adopted the provisions of EITF 98-10,
pursuant to the implementation requirements stated therein. The resulting effect
of adoption of the provisions of EITF 98-10 was to alter the Company's
comprehensive method of accounting for energy-related contracts, as defined in
that Statement.
The Company accounts for all energy trading activities at fair value as of the
balance sheet date and recognizes currently the net gains or losses resulting
from the revaluation of these contracts to fair value in its results of
operations. As a result, substantially all of the energy trading activities of
the Company's gas marketing, crude oil marketing, and coal marketing operations
are accounted for under fair value accounting methodology as prescribed in EITF
98-10.
The Company, through its independent energy business group, utilizes financial
instruments for its fuel marketing services. These financial instruments include
fixed-for-float swap financial instruments, basis swap financial instruments and
costless collars traded in the over-the-counter financial markets.
These derivatives are not held for speculative purposes but rather serve to
hedge the Company's exposure related to commodity purchases or sales
commitments. Under EITF 98-10, these transactions qualify as energy trading
activities that must be accounted for at fair value. As such, realized and
unrealized gains and losses are recorded as a component of income. Because the
Company does not as a policy permit speculation with "open" positions,
substantially all of its trading activities are back-to-back positions where a
commitment to buy/(sell) a commodity is matched with a committed sale/(buy) or
financial instrument.
The quantities and maximum terms of derivative financial instruments held for
trading purposes at December 31, 2000 and 1999 are as follows:
Max. Term
December 31, 2000 Volume Covered (Years)
- ----------------- -------------- -------
(MMBtus)
Natural gas basis swaps purchased 25,577,894 2
Natural gas basis swaps sold 26,059,621 2
Natural gas fixed-for-float swaps purchased 6,476,222 1
Natural gas fixed-for-float swaps sold 7,360,560 1
(Tons)
Coal tons sold 988,000 1
Coal tons purchased 896,000 1
Max. Term
December 31, 1999 Volume Covered (Years)
- ----------------- -------------- -------
(MMBtus)
Natural gas futures contracts purchased 860,000 1
Natural gas basis swaps purchased 17,741,500 4
Natural gas basis swaps sold 18,390,517 4
Natural gas fixed-for-float swaps purchased 9,490,486 1
Natural gas fixed-for-float swaps sold 10,994,521 1
Natural gas collar transactions; puts purchased, calls sold 408,500 1
Natural gas collar transactions; calls purchased, puts sold 318,500 1
As required under EITF 98-10, energy trading activities were marked to fair
value on December 31, 2000, and the gains and losses recognized in earnings. The
entries for the accompanying consolidated balance sheet and income statement are
as follows (in thousands):
Instrument Asset Liability Gain (loss)
- ---------- ----- --------- ----------
Natural gas basis swaps $13,391 $23,963 $(10,572)
Natural gas fixed-for-float swaps 24,617 27,110 (2,493)
Natural gas physical 23,391 9,427 13,964
Coal transactions 5,370 4,460 910
Crude oil transactions 1,523 1,000 523
------- ------- --------
Totals $68,292 $65,960 $ 2,332
======= ======= ========
There were no significant differences between the fair values of derivative
assets and liabilities at December 31, 1999.
Non-trading Energy Activities
To reduce risk from fluctuations in the price of oil and natural gas, the
Company enters into swaps and costless collar transactions. The transactions are
used to hedge price risk from sales of the Company's forecasted crude oil and
natural gas production. For such transactions, the Company utilizes hedge
accounting.
At December 31, 2000, the Company had fixed-for-float swaps for 17,000 barrels
per month for the year 2001 to hedge its crude oil price risk with a fair value
that approximates cost. The Company had fixed-for-float swaps for 10,000 barrels
per month for the year 2002 to hedge its crude oil price risk with a fair value
of $0.4 million. The Company also had costless collars (purchased puts - sold
calls) for 10,000 barrels per month for 2001 with a fair value of $0.3 million.
The Company hedged its forecasted 2001 natural gas production with
fixed-for-float swaps. The Company had fixed-for-float swaps for 1,581,000
MMBtus with a fair value of $(3.4) million. These amounts are not reflected in
the Company's December 31, 2000 consolidated balance sheet, but will be recorded
as part of the adoption of SFAS 133 on January 1, 2001.
Financing Activities
To reduce risk from fluctuations in interest rates, the Company enters into
interest rate swap transactions. These transactions are used to hedge interest
rate risk for variable rate debt financing. For such transactions, the Company
utilizes hedge accounting. At December 31, 2000, the Company had interest rate
swaps with a notional amount of $127.4 million, having a maximum term of six
years and a fair value of $(7.5) million.
At December 31, 2000, the Company had $162.2 million of outstanding,
floating-rate debt of which $34.8 million was not offset with interest rate swap
transactions that effectively convert the debt to a fixed rate.
Credit Risk
In addition to the risk associated with price movements, credit risk is also
inherent in the Company's risk management activities. Credit risk relates to the
risk of loss resulting from non-performance of contractual obligations by a
counterparty. While the Company has not experienced significant losses due to
the credit risk associated with these arrangements, the Company has off-balance
sheet risk to the extent that the counterparties to these transactions may fail
to perform as required by the terms of each such contract.
(3) INVESTMENTS IN ASSOCIATED COMPANIES
Included in Investments on the Consolidated Balance Sheets are the following
investments that have been recorded on the equity method of accounting:
o A 33.33 percent interest in Millennium Pipeline Company, L.P., a Texas
limited partnership which owns and operates an oil pipeline in the Gulf
Coast region of Texas. The Company has a carrying amount in the investment
of $6.9 million and $4.8 million as of December 31, 2000 and 1999,
respectively. The partnership had assets of $22.0 million and $15.7
million, liabilities of $1.0 million and $1.6 million, and net income
(loss) of $2.8 million and $(0.2) million as of, and for the years ended
December 31, 2000 and 1999, respectively.
o As part of the Indeck Capital, Inc. acquisition, the Company acquired a 5
percent, 6 percent and 5 percent interest in Energy Investors Fund, L.P.,
Energy Investors Fund II, L.P., and Project Finance Fund III, L.P.,
respectively, which in turn have investments in numerous electric
generating facilities in the United States and elsewhere. The Company has a
carrying amount in the investment of $8.4 million at December 31, 2000. As
of, and for the year ended December 31, 2000, the funds had assets of
$186.8 million, liabilities of $16.0 million and net income of $27.1
million.
o As part of the Indeck Capital acquisition, the Company acquired a 50
percent financial interest in two natural gas-fired cogeneration facilities
located in Rupert and Glenns Ferry, Idaho. At December 31, 2000 the
Company's carrying amount in the investment is $4.1 million which includes
$0.5 million that represents the cost of the investment over the value of
the underlying net assets of the projects. This excess is being amortized
over 19 years. As of, and for the year ended December 31, 2000, these
projects had assets of $26.0 million, liabilities of $18.7 million and net
income of $0.9 million.
o As part of the Indeck Capital acquisition, the Company directly and
indirectly acquired approximately 32 percent of Harbor Cogeneration
Company, which in turn owns an 80 megawatt cogeneration facility located
near the City of Long Beach in Los Angeles County, California. At December
31, 2000 the Company's carrying amount in the investment is $42.2 million,
which includes $13.7 million that represents the cost of the investment
over the value of the underlying net assets of Harbor. This excess is being
amortized over 15 years. As of, and for the year ended December 31, 2000,
Harbor had assets of $41.7 million, liabilities of $0.8 million and net
income of $28.8 million.
(4) COMMON STOCK
During 2000, the Company became a wholly-owned subsidiary of Black Hills
Corporation. See Note 1 - Business Description. Black Hills Corporation assumed
all of the Company's stock option, employee stock purchase and dividend
reinvestment and stock purchase plans.
(5) PREFERRED STOCK
During 2000, the Company issued 4,000 preferred shares in the Indeck Capital
acquisition. The preferred shares issued were non-voting, cumulative, no par
shares with a dividend rate equal to 1 percent per annum per share, computed on
the basis of $1,000 per share plus an amount equal to any dividend declared
payable with respect to the common stock, multiplied by the number of shares of
common stock into which each share of preferred stock is convertible.
In the "plan of exchange" with Black Hills Corporation, the preferred stock held
by the Indeck shareholders was exchanged for preferred stock of the holding
company and the Company converted all of its preferred stock held by the holding
company into shares of common stock.
(6) LONG-TERM DEBT
Long-term debt outstanding at December 31 is as follows (in thousands):
2000 1999
---- ----
First mortgage bonds:
6.50% due 2002 $ 15,000 $ 15,000
9.00% due 2003 3,215 4,255
8.06% due 2010 30,000 30,000
9.49% due 2018 5,130 5,420
9.35% due 2021 35,000 35,000
8.30% due 2024 45,000 45,000
--------- --------
133,345 134,675
--------- --------
Other long-term debt:
Pollution control revenue bonds at 6.7% due 2010 12,300 12,300
Pollution control revenue bonds at 7.5% due 2024 12,200 12,200
Other 3,911 2,855
--------- --------
28,411 27,355
--------- --------
Project financing debt:
Floating-rate term loans at a weighted average rate of 8.05%
at December 31, 2000 due 2009 through 2010 (a) 159,296 -
--------- ---------
Total long-term debt 321,052 162,030
Less current maturities (13,960) (1,330)
--------- ---------
Net long-term debt $ 307,092 $160,700
========= =========
- ---------------
(a) Approximately 80 percent of the December 31, 2000 balance has been
hedged with an interest rate swap moving the floating rates to fixed
rates with a weighted average interest rate of 7.69 percent (see Note
2-Price Risk Management).
Substantially all of the Company's utility property is subject to the lien of
the indenture securing its first mortgage bonds. First mortgage bonds of the
Company may be issued in amounts limited by property, earnings and other
provisions of the mortgage indentures.
Project financing debt is non-recourse debt collateralized by a mortgage on each
respective project's land and facilities, leases and rights, including rights to
receive payments under long-term purchase power contracts.
Certain debt instruments of the Company and its subsidiaries contain restrictive
covenants, all of which the Company and its subsidiaries are in compliance with
at December 31, 2000.
Scheduled maturities for the next five years are: $14.0 million in 2001, $30.0
million in 2002, $16.0 million in 2003, $16.4 million in 2004, and $17.6 million
in 2005.
(7) NOTES PAYABLE
The Company had committed lines of credit with various banks of $290.0 million
at December 31, 2000 and $115.0 million at December 31, 1999, which were
available to support bank borrowings or to provide for letters of credit. There
were $211.0 million of borrowings and $20.6 million of letters of credit issued
under these lines of credit at December 31, 2000, and there were $96.6 million
of borrowings and no letters of credit issued at December 31, 1999. The Company
has no compensating balance requirements associated with these lines of credit.
The lines of credit are subject to periodic review and renewal during the year
by the banks.
In addition to the above lines of credit, Enserco Energy, Inc. has a $90.0
million uncommitted, discretionary line of credit to provide support for the
purchases of natural gas. The Company and its subsidiaries provide no guarantee
to the lender. At December 31, 2000 and 1999, there were outstanding letters of
credit issued under the facility of $69.8 million and $19.9 million
respectively, with no borrowing balances on the facility.
In addition to the above lines of credit, Black Hills Energy Resources, Inc. has
a $25.0 million uncommitted, discretionary credit facility. The transactional
line of credit provides credit support for the purchases of crude oil of Black
Hills Energy Resources. The Company and its subsidiaries provide no guarantee to
the lender. At December 31, 2000 and 1999, Black Hills Energy Resources, Inc.
had letters of credit outstanding of $8.5 million and $13.2 million,
respectively and no balance outstanding on the overdraft line.
Our credit facilities contain restrictive covenants and include commitment fees
ranging from .125 percent to .375 percent; our credit facilities with ABN AMRO
Bank, NV also include utilization fees of .75 percent on the amount by which
facility loans exceed 50 percent of the total facility commitment. The Company
and its subsidiaries had complied with all the covenants at December 31, 2000.
Interest rates under the facility borrowings vary and are based, at the option
of the Company at the time of the loan origination, on either (i) a prime based
borrowing rate varying from prime rate (9.5 percent at December 31, 2000) to
prime rate plus 1.5 percent, or (ii) on the London Interbank Offered Rate
(LIBOR) (6.5 percent for a one-month LIBOR at December 31, 2000) based
borrowings rates varying from LIBOR plus .625 percent to LIBOR plus 1.375
percent.
(8) FAIR VALUE OF FINANCIAL INSTRUMENTS
Cash of the Company is invested in money market investments such as municipal
put bonds, money market preferreds, commercial paper, Eurodollars and
certificates of deposit.
The following methods and assumptions were used to estimate the fair value of
each class of the Company's financial instruments.
Cash and Cash Equivalents
The carrying amount approximates fair value due to the short maturity of these
instruments.
Available-for-sale Securities
The fair value of the Company's investments equals the quoted market price when
available and a quoted market price for similar securities if a quoted market
price is not available. The Company has classified all of its marketable
securities as available-for-sale as of December 31, 2000 and 1999. An unrealized
loss on the Company's investments of $0.8 million was recorded as of December
31, 2000. At December 31, 1999 fair value approximated cost.
Long-Term Debt
The fair value of the Company's long-term debt is estimated based on quoted
market rates for utility debt instruments having similar maturities and similar
debt ratings. The Company's outstanding bonds are either currently not callable
or are subject to make-whole provisions which would eliminate any economic
benefits for the Company to call and refinance the bonds.
The estimated fair values of the Company's financial instruments are as follows:
2000
----
(in thousands)
Carrying Amount Fair Value
--------------- ----------
Cash and cash equivalents $ 24,913 $ 24,913
Securities available-for-sale 2,113 2,113
Long-term debt 321,052 337,446
1999
----
(in thousands)
Carrying Amount Fair Value
--------------- ----------
Cash and cash equivalents $ 16,482 $ 16,482
Securities available-for-sale 7,586 7,586
Long-term debt 162,030 165,958
(9) WYODAK PLANT
The Company owns a 20 percent interest and Pacific Power owns an 80 percent
interest in the Wyodak plant (Plant), a 330 megawatt coal-fired electric
generating station located in Campbell County, Wyoming. Pacific Power is the
operator of the Plant. The Company receives 20 percent of the Plant's capacity
and is committed to pay 20 percent of its additions, replacements and operating
and maintenance expenses. As of December 31, 2000, the Company's investment in
the Plant included $71.8 million in electric plant and $22.4 million in
accumulated depreciation. The Company's share of direct expenses of the Plant
was $5.6 million, $4.9 million and $5.8 million for the years ended December 31,
2000, 1999 and 1998, respectively, and is included in the corresponding
categories of operating expenses in the accompanying consolidated statements of
income. Wyodak Resources supplies coal to the Plant under an agreement expiring
in 2013 with a Pacific Power option to renew the agreement for an additional 10
years. This coal supply agreement is collateralized by a mortgage on and a
security interest in some of Wyodak Resources' coal reserves. At December 31,
2000, approximately 17,966,000 tons of coal were covered under this agreement.
Wyodak Resources' sales to the Plant were $23.2 million, $24.9 million and $23.2
million, for the years ended December 31, 2000, 1999 and 1998, respectively.
(10) COMMITMENTS AND CONTINGENCIES
Pacific Power's Power Sales Agreement
In 1983, the Company entered into a 40 year power agreement with Pacific Power
providing for the purchase by the Company of 75 megawatts of electric capacity
and energy from Pacific Power's system. An amended agreement signed in October
1997 reduces the contract capacity by 25 megawatts (5 megawatts per year
starting in 2000). The price paid for the capacity and energy is based on the
operating costs of one of Pacific Power's coal-fired electric generating plants.
Costs incurred under this agreement were $14.6 million, $17.8 million and $17.5
million in 2000, 1999 and 1998, respectively.
Reclamation
Under its mining permit, Wyodak Resources is required to reclaim all land where
it has mined coal reserves. The cost of reclaiming the land is accrued as the
coal is mined. While the reclamation process takes place on a continual basis,
much of the reclamation occurs over an extended period after the area is mined.
Approximately $0.7 million is charged to operations as reclamation expense
annually. As of December 31, 2000, accrued reclamation costs were approximately
$17.7 million.
Legal Proceedings
On August 14, 2000, Wyodak Resources Development Corp. ("Wyodak") initiated an
action against PacifiCorp as it concerns the Further Restated and Amended Coal
Supply Agreement, dated as of May 5, 1987 ("Coal Supply Agreement"). The action
has been filed in the United States District Court for the District of Wyoming
as Case No. 00CV155-B. Wyodak alleges that PacifiCorp has failed and refused to
make complete payment to Wyodak for coal sold under the Coal Supply Agreement,
and there was at that time approximately $5.0 million outstanding and allegedly
due Wyodak from PacifiCorp. Wyodak alleged that PacifiCorp's actions constitute
a breach of contract and asked for the appropriate monetary relief.
On August 31, 2000, PacifiCorp answered the Wyodak Complaint and additionally
brought a counterclaim against Wyodak and Black Hills Corporation. In its
action, PacifiCorp alleged that as a result of Wyodak's actions as it concerns
its billings under the Coal Supply Agreement, PacifiCorp was entitled to cancel
and terminate the Coal Supply Agreement and Coal Handling Agreement, as well as
the recovery of damages. PacifiCorp alleged that Wyodak had not properly
adjusted upward and downward the components which make up the coal price under
the Coal Supply Agreement, and as a result PacifiCorp had been overbilled
appproximately $35.0 million to $40.0 million and that Wyodak continued to
overcharge PacifiCorp under the Coal Supply Agreement and the Coal Handling
Agreement. PacifiCorp further alleged that the overcharges would result in
additional overcharges of approximately $150.0 million through the balance of
the term of the Coal Supply Agreement, which expires in June of 2013. In its
action, PacifiCorp sought not only to cancel and terminate the contract but also
to discharge and excuse any further obligation under the same, as well as
recovery of damages as set forth above.
Management is of the opinion that Wyodak has properly billed PacifiCorp under
the terms of the Coal Supply Agreement and Coal Handling Agreement and
PacifiCorp's withholding of payment constitutes a breach of contract on their
part. Although it is impossible to predict whether or not Black Hills
Corporation and Wyodak will ultimately be successful in defending the claim or,
if not, what the impact might be, management believes that the disposition of
this matter will not have a material adverse effect on the Company's
consolidated results of operations.
In addition, the Company is subject to various legal proceedings and claims
which arise in the ordinary course of operations. In the opinion of management,
the amount of liability, if any, with respect to these actions would not
materially affect the consolidated financial position or results of operations
of the Company.
(11) EMPLOYEE BENEFIT PLANS
Defined Benefit Pension and Other Postretirement Plans
The Company has a noncontributory defined benefit pension plan (Plan) covering
the employees of Black Hills Power, Wyodak Resources Development Corp., Black
Hills Exploration and Production and Daksoft who meet certain eligibility
requirements. The benefits are based on years of service and compensation levels
during the highest five consecutive years of the last ten years of service. The
Company's funding policy is in accordance with the federal government's funding
requirements. The Plan's assets are held in trust and consist primarily of
equity securities and cash equivalents.
Net pension income for the Plan was as follows:
2000 1999 1998
---- ---- ----
(in thousands)
Service cost $ 967 $ 1,174 $ 895
Interest cost 2,885 2,598 2,406
Estimated return on assets (5,257) (4,162) (4,146)
Amortization of transition amount (90) (90) (90)
Amortization of prior service cost 231 89 89
Recognized net actuarial gain (537) - (272)
-------- --------- --------
Net pension income $ (1,801) $ (391) $(1,118)
======== ========= ========
Actuarial assumptions:
Discount rate 7.5% 6.75% 7.5%
Expected long-term rate of return on assets 10.5% 10.5% 10.5%
Rate of increase in compensation levels 5.0% 5.0% 5.0%
A reconciliation of the beginning and ending balances of the projected benefit
obligation is as follows:
2000 1999
---- ----
(in thousands)
Beginning projected benefit obligation $39,615 $39,490
------- -------
Service cost 967 1,174
Interest cost 2,885 2,598
Actuarial losses (48) (3,590)
Benefits paid (2,105) (1,903)
Plan amendments - 1,846
------- -------
Net increase 1,699 125
------- -------
Ending projected benefit obligation $41,314 $39,615
======= =======
A reconciliation of the fair value of plan assets as of October 1 of each year
is as follows:
2000 1999
---- ----
(in thousands)
Beginning market value of plan assets $51,212 $40,638
Benefits paid (2,105) (1,903)
Investment income 7,453 12,477
--------- --------
Ending market value of plan assets $56,560 $51,212
======= =======
Funding information for the Plan as of October 1 each year was as follows:
2000 1999
---- ----
(in thousands)
Fair value of plan assets $56,560 $51,212
Projected benefit obligation (41,314) (39,615)
------- -------
Funded status 15,246 11,597
Unrecognized:
Net gain (13,812) (12,105)
Prior service cost 2,054 2,285
Transition asset - (90)
------- -------
Prepaid pension cost $ 3,488 $ 1,687
======= =======
Accumulated benefit obligation $33,374 $31,914
======= =======
The Company has various supplemental retirement plans for outside directors and
key executives of the Company. The plans are nonqualified defined benefit plans.
Expenses recognized under the plans were $0.5 million, $0.4 million and $0.4
million in 2000, 1999 and 1998, respectively.
Employees who are participants in the Plan and who retire from the Company on or
after attaining age 55 after completing at least five years of service to the
Company are entitled to postretirement healthcare benefits coverage. These
benefits are subject to premiums, deductibles, copayment provisions and other
limitations. The Company may amend or change the plan periodically. The Company
is not pre-funding its retiree medical plan.
The net periodic postretirement cost was as follows:
2000 1999 1998
---- ---- ----
(in thousands)
Service cost $282 $225 $135
Interest cost 523 362 290
Amortization of transition obligation 150 150 150
(Gain)/loss 68 1 (42)
------ ---- ----
$1,023 $738 $533
====== ==== ====
Funding information as of October 1 was as follows:
2000 1999
---- ----
(in thousands)
Accumulated postretirement benefit obligation:
Retirees $2,478 $2,608
Fully eligible active participants 1,203 1,195
Other active participants 3,172 3,278
------- -------
Unfunded accumulated postretirement benefit obligation 6,853 7,081
Unrecognized net loss (1,001) (1,667)
Unrecognized transition obligation (1,797) (1,947)
------- -------
Accrued postretirement cost $4,055 $3,467
====== ======
For measurement purposes, an 8.5 percent annual rate of increase in healthcare
benefits was assumed for 2000; the rate was assumed to decrease gradually to 6
percent in 2005 and remain at that level thereafter. The healthcare cost trend
rate assumption has a significant effect on the amounts reported. A one percent
increase in the healthcare cost trend assumption would increase the service and
interest cost $0.2 million or 21.8 percent and the net periodic postretirement
cost $0.2 million or 24.1 percent. A one percent decrease would reduce the
service and interest cost by $0.1 million or 16.9 percent and decrease the net
periodic postretirement cost $0.2 million or 18.6 percent. The weighted-average
discount rate used in determining the accumulated postretirement benefit
obligation was 7.5 percent.
Defined Contribution Plan
The Company also sponsors a 401(k) savings plan for eligible employees.
Participants elect to invest up to 20 percent of their eligible compensation on
a pre-tax basis. Effective January 1, 2000 (May 1, 2000 for employees covered by
the collective bargaining agreement), the Company provides a matching
contribution of 100 percent of the employee's tax-deferred contribution up to a
maximum 3 percent of the employee's eligible compensation. Matching
contributions vest at 20 percent per year and are fully vested when the
participant has 5 years of service with the Company. The Company's matching
contributions totaled $0.6 million for 2000.
(12) INCOME TAXES
Income tax expense for the years indicated was:
2000 1999 1998
---- ---- ----
(in thousands)
Current $28,421 $13,498 $14,243
Deferred 2,576 2,931 (1,886)
Tax credits, net (639) (640) (649)
------- ------- -------
$30,358 $15,789 $11,708
======= ======= =======
The temporary differences which gave rise to the net deferred tax liability at
December 31, 2000 and 1999 were as follows:
Net Deferred
Income
Tax Asset
December 31, 2000 Assets Liabilities (Liability)
------ ----------- -----------
(in thousands)
Accelerated depreciation and other plant-related
differences $ 5,393 $63,559 $(58,166)
Regulatory asset 1,621 - 1,621
Regulatory liability - 1,447 (1,447)
Unamortized investment tax credits 886 - 886
Mining development and oil exploration 3,605 8,450 (4,845)
Employee benefits 3,308 1,347 1,961
Other 3,711 6,400 (2,689)
------- ------- --------
$18,524 $81,203 $(62,679)
======= ======= ========
Net Deferred
Income
Tax Asset
December 31, 1999 Assets Liabilities (Liability)
------ ----------- -----------
(in thousands)
Accelerated depreciation and other plant-related
differences $ - $48,223 $(48,223)
Regulatory asset 1,792 - 1,792
Regulatory liability - 1,380 (1,380)
Unamortized investment tax credits 1,058 - 1,058
Mining development and oil exploration 3,605 6,893 (3,288)
Employee benefits 2,833 695 2,138
Other 2,184 1,949 235
------- ------- --------
$11,472 $59,140 $(47,668)
======= ======= ========
The effective tax rate differs from the federal statutory rate for the years
ended December 31, as follows:
2000 1999 1998
---- ---- ----
Federal statutory rate 35.0% 35.0% 35.0%
State income tax 1.4 - -
Amortization of investment tax credits (1.0) (0.9) (1.3)
Tax-exempt interest income - (0.5) (1.1)
Percentage depletion in excess of cost (1.1) (1.6) (1.7)
Other 2.2 (2.1) 0.3
----- ------ -----
36.5% 29.9% 31.2%
==== ==== ====
(13) BUSINESS SEGMENTS
The Company's reportable segments are those that are based on the Company's
method of internal reporting, which generally segregates the strategic business
groups due to differences in products, services and regulation. As of December
31, 2000, substantially all of the Company's operations and assets are located
within the United States. The Company's operations are conducted through six
business segments that include: Electric, which supplies electric utility
service to western South Dakota, northeastern Wyoming and southeastern Montana;
Independent Energy consisting of: Mining, which engages in the mining and sale
of coal from its mine near Gillette, Wyoming; Oil and Gas, which produces,
explores and operates oil and gas interests located in the Rocky Mountain
region, Texas, California and other states; Fuel Marketing, which markets
natural gas, oil, coal and related services to customers in the East Coast,
Midwest, Southwest, Rocky Mountain, West Coast and Northwest regions markets;
Independent Power, which produces and sells power to wholesale customers; and
Communications and Others, which primarily markets communications and software
development services.
Segment information follows the same accounting policies as described in Note 1
- - BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES. Segment
information included in the accompanying Consolidated Balance Sheets and
Consolidated Statements of Income is as follows (in thousands):
ASSETS Independent Energy
--------------------------------------------------
Oil and Fuel Independent Communications
Electric Mining Gas Marketing Power & Others Eliminations Total
------------- ---------- ----------- ------------ -------------- ----------------- ------------- ------------
At December 31, 2000
Current assets $ 133,542 $167,820 $ 3,452 $ 330,352 $ 25,645 $ 13,213 $ (255,016) $ 419,008
Total assets 627,930 251,136 36,396 346,333 375,811 132,722 (440,943) 1,329,385
At December 31, 1999
Current assets $ 93,837 $ 57,427 $ 1,988 $ 84,867 $ 52,471 $ 9,698 $ (113,931) $ 186,357
Total assets 522,285 136,372 29,381 99,064 52,690 72,711 (244,011) 668,492
At December 31, 1998
Current assets $ 43,760 $ 25,872 $ 1,335 $ 77,402 $ 4 $ 6,067 $ (13,960) $ 140,480
Total assets 451,404 93,480 26,666 86,300 57 18,441 (116,931) 559,417
Independent Energy
--------------------------------------------------
Year ended Oil and Fuel Independent Communications
December 31, 2000 Electric Mining Gas Marketing Power & Others Eliminations Total
------------- ---------- ----------- ------------ -------------- ----------------- ------------- ------------
Electric revenues $ 173,308 $ - $ - $ - $ - $ - $ - $ 173,308
Coal revenues - 30,530 - 37,099 - - - 67,629
Gas revenues - - 9,335 871,296 - - (14,320) 866,311
Oil revenues - - 7,211 458,575 - - - 465,786
Other operating
Revenues - - 3,782 - 39,660 11,371 (4,011) 50,802
---------- ---------- ----------- ------------ -------------- ----------------- ------------- -------------
Total operating
Revenues $ 173,308 $ 30,530 $ 20,328 $1,366,970 $ 39,660 $ 11,371 $ (18,331) $ 1,623,836
---------- ---------- ----------- ------------ -------------- ----------------- ------------- -------------
Depreciation, depletion
and amortization $ 14,966 $3,525 $ 4,071 $ 644 $ 3,646 $ 6,012 $ - $ 32,864
Operating income (loss) 68,208 8,794 7,906 23,774 20,374 (14,306) - 114,750
Interest expense 17,411 8,006 372 535 11,911 6,350 (14,243) 30,342
Income taxes (benefit) 19,469 2,660 2,609 9,323 3,154 (6,857) - 30,358
Net income (loss)
available for common 37,100 7,173 4,992 14,009 3,241 (12,557) (1,188) 52,770
Property additions,
investments and
acquisition of net assets 25,257 2,419 9,259 (3) 81,335* 58,922 - 177,189
*Excludes the non-cash acquisition of Indeck Capital, Inc. as described in Note 14.
Independent Energy
--------------------------------------------------
Year ended Oil and Fuel Independent Communications
December 31, 1999 Electric Mining Gas Marketing Power & Others Eliminations Total
------------- ---------- ----------- ------------ -------------- ----------------- ------------- ----------
Electric revenues $ 133,222 $ - $ - $ - $ - $ - $ - $ 133,222
Coal revenues - 31,095 - 39,212 - - - 70,307
Gas revenues - - 5,399 382,809 - - - 388,208
Oil revenues - - 4,676 192,207 - - - 196,883
Other operating
Revenues - - 2,977 - - 3,423 (3,145) 3,255
------------- ---------- ----------- ------------ -------------- ----------------- ------------- -----------
Total operating
Revenues $ 133,222 $ 31,095 $ 13,052 $ 614,228 $ - $ 3,423 $(3,145) $ 791,875
------------- ---------- ----------- ------------ -------------- ----------------- ------------- -----------
Depreciation, depletion
and amortization $ 15,552 $ 3,259 $ 2,953 $ 2,757 $ - $ 546 $ - $ 25,067
Operating income (loss) 52,286 12,606 3,978 (2,248) (157) (4,574) - 61,891
Interest expense 13,830 1,260 568 719 111 1,172 (2,200) 15,460
Income taxes (benefit) 12,446 3,439 968 50 (58) (1,056) - 15,789
Net income (loss)
available for common 27,362 9,715 2,462 (185) (109) (1,263) (915) 37,067
Property additions,
investments and
acquisition of net assets 31,911 5,422 9,968 5,947 52,319 49,042 - 154,609
Independent Energy
---------------------------------------------------
Year ended Oil and Fuel Independent Communications
December 31, 1998 Electric Mining Gas Marketing Power & Others Eliminations Total
------------- ---------- ------------ ------------ -------------- ----------------- ------------- ----------
Electric revenues $ 129,236 $ - $ - $ - $ - $ - $ - $ 129,236
Coal revenues - 31,413 - 12,924 - - - 44,337
Gas revenues - - 4,073 375,136 - - - 379,209
Oil revenues - - 5,131 117,185 - - - 122,316
Other operating
Revenues - - 3,358 798 - 2,437 (2,437) 4,156
------------- ---------- ------------ ------------ -------------- ----------------- ------------- ----------
Total operating
Revenues $ 129,236 $ 31,413 $ 12,562 $ 506,043 $ - $ 2,437 $ (2,437) $ 679,254
------------ ---------- ------------ ------------ -------------- ----------------- ------------- ----------
Depreciation, depletion
and amortization
$ 14,881 $ 3,252 $ 18,760** $ 690 $ - $ - $ - $ 37,583
Operating income
(loss) 49,896 12,723 (12,340)** 41 - (1,087) - 49,233
Interest income 13,572 10 355 731 - 39 - 14,707
Income taxes (benefit) 12,612 4,126 (4,689)** (116) (64) (161) - 11,708
Net income (loss)
available for common 24,825 9,750 (7,976)** (346) (118) (226) (101) 25,808
Property additions,
investments and
acquisition of net
assets 11,451 1,406 10,169 2,384 - 1,815 - 27,225
**Includes the impact of a $13.5 million pre-tax write-down of certain oil and natural gas properties.
(14) ACQUISITIONS
On July 7, 2000, the Company acquired Indeck Capital, Inc. and merged it into
Black Hills Energy Capital, Inc. The new entity owns varying financial interests
in 14 operating independent power plants in California, New York, Massachusetts,
Colorado and Idaho totaling approximately 350 megawatts.
The acquisition was a stock transaction with the Company issuing 1,536,747
shares of common stock to the shareholders of Indeck priced at $21.98 per share
(approximately 7 percent of the Company's common stock after the transaction),
along with $4
million in preferred stock, resulting in a purchase price of approximately $37.8
million. Additional consideration, consisting of common and preferred stock, may
be paid in the form of an earn-out over a four-year period. The earn-out
consideration will be based on the acquired company's earnings during such
period and cannot exceed $35.0 million in total. Additional consideration paid
out under the earn-out will be recorded as an increase to goodwill.
The acquisition has been accounted for under the purchase method of accounting
and, accordingly, the purchase price has been allocated to the acquired assets
and liabilities based on estimates of the fair values of the assets purchased
and the liabilities assumed as of the date of acquisition. Fair values in the
allocation include assets acquired of approximately $151.1 million (excluding
goodwill) and liabilities assumed of approximately $138.7 million. As of
December 31, 2000, the purchase price and related acquisition costs exceeded the
fair values assigned to net tangible assets by approximately $25.4 million,
which was recorded as goodwill and is being amortized over 25 years on a
straight-line basis.
Prior to the closing of the Indeck Capital transaction, there was no material
relationship between its shareholders and the Company or any of its affiliates,
any director or officer of the Company or any of their associates, except that
the Company through its subsidiaries and Indeck Capital jointly owned Black
Hills Colorado, LLC and both parties held interests in Indeck North American
Power Partners, L.P. and Indeck North American Power Fund, L.P. Black Hills
Colorado owns 111 megawatts of combustion turbine generating facilities in the
Front Range of Colorado.
In addition, the Company made several step-acquisitions resulting in
consolidation of $169.5 million of assets and $138.8 million of liabilities. The
related transactions are as follows:
o Through various transactions, acquired an additional 27.11 percent interest
in Indeck North American Power Fund, L.P. and an additional 46.66 percent
interest in Indeck North American Power Partners, L.P., for approximately
$13.0 million in cash.
o Acquired a 39.6 percent financial interest in each of Northern Electric
Power Company, L.P. and South Glens Falls Limited Partnership for
approximately $4.2 million in cash.
o Acquired substantially all of the partnership interests in Middle Falls
Limited Partnership, Sissonville Limited Partnership and New York State Dam
Limited Partnership for approximately $12.9 million in cash.
Operating activities of the above acquired companies have been included in the
accompanying consolidated financial statements since their respective
acquisition dates. The following unaudited pro forma condensed results of
operations presents the effect of the acquisitions as if they had occurred on
January 1, 1999. The pro forma financial data is provided for informational
purposes only and does not purport to be indicative of the results that would
have been obtained if the acquisitions had been effected on January 1, 1999. The
pro forma financial information reflects the amortization of the excess purchase
price over the fair value of net assets acquired and the income tax effect
thereof for the years ended December 31, 2000 and 1999 as follows:
2000 1999
---- ----
(Unaudited, in thousands)
Revenues $1,668,851 $840,891
Operating income $139,053 $73,900
Net income available for common stock $57,542 $34,310
(15) OIL AND GAS RESERVES (Unaudited)
Black Hills Exploration and Production has interests in 639 producing oil and
gas properties in seven states. Black Hills Exploration and Production also
holds leases on approximately 185,926 net undeveloped acres.
The following table summarizes Black Hills Exploration and Production's
quantities of proved developed and undeveloped oil and natural gas reserves,
estimated using constant year-end product prices, as of December 31, 2000, 1999
and 1998, and a reconciliation of the changes between these dates. These
estimates are based on reserve reports by Ralph E. Davis Associates,
Inc., an independent engineering company selected by the Company. Such reserve
estimates are based upon a number of variable factors and assumptions which may
cause these estimates to differ from actual results.
2000 1999 1998
---- ---- ----
Oil Gas Oil Gas Oil Gas
--- --- --- --- --- ---
(in thousands of barrels of oil and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year 4,109 19,460 2,368 15,952 2,495 9,052
Production (352) (3,285) (309) (2,801) (353) (2,068)
Additions 625 4,228 376 7,718 1,149 10,721
Property sales - - (164) (66) - -
Revisions to previous estimates 31 (1,999) 1,838 (1,343) (923) (1,753)
------- ------- ------- -------- ------- --------
Balance at end of year 4,413 18,404 4,109 19,460 2,368 15,952
======= ======= ======= ======= ======= =======
Proved developed reserves at end of
year included above 3,047 16,418 2,819 14,391 1,463 10,041
======= ======= ======= ======= ======= =======
Year-end prices $26.80 $9.78 $24.28 $1.99 $9.16 $1.93
====== ===== ====== ===== ===== =====
In December 1998, Black Hills Exploration and Production recognized a $13.5
million pre-tax loss related to a write-down of oil and gas properties. The
write-down was primarily due to historically low crude oil prices, lower natural
gas prices and decline in value of certain unevaluated properties.
(16) QUARTERLY HISTORICAL DATA (Unaudited)
The Company operates on a calendar year basis. The following table sets forth
selected unaudited historical operating results and market data for each quarter
of 2000 and 1999.
First Second Third Fourth
Quarter Quarter Quarter Quarter
------- ------- ------- -------
(in thousands)
2000:
Operating revenues $247,959 $336,978 $453,231 $585,668
Operating income 16,872 15,200 42,519 40,159
Net income available
for common stock 9,061 8,061 16,285 19,363
1999:
Operating revenues $168,201 $186,195 $219,779 $217,700
Operating income 15,980 13,786 16,675 15,450
Net income available
for common stock 9,035 7,763 9,725 10,544
(17) SUBSEQUENT EVENT (Unaudited)
On March 8, 2001, Black Hills Energy Capital, Inc., the Company's independent
power subsidiary announced it had signed a definitive agreement to purchase a
240 megawatt gas-fired turbine generation facility (Fountain Valley) located
near Colorado Springs, Colorado from Enron Corporation. The transaction is
expected to close around March 31, 2001.
The Fountain Valley facility features six LM-6000 simple-cycle, gas-fired
turbines, a technology identical to existing Company facilities in Colorado and
Wyoming. All necessary permitting has been approved and the plant is expected to
phase in its generation capacity beginning in May 2001. The Company also
announced that it has signed an 11-year contract with Public Service of Colorado
to utilize the plant for peaking purposes. The contract is a tolling arrangement
in which the Company assumes no fuel costs. The cost of the project is expected
to be approximately $175 million. The Company expects to finance the project
primarily with non-recourse debt and negotiations are presently under way with
certain lenders.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No change of accountants or disagreements on any matter of accounting principles
or practices or financial statement disclosure have occurred.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements
Financial statements required by Item 14 are listed in the index
included in Item 8 of Part II.
2. Schedules
All schedules have been omitted because of the absence of the
conditions under which they are required or because the required
information is included elsewhere in the financial statements
incorporated by reference in the Form 10-K.
3. Exhibits
Exhibit
Number Description
2* Plan of Exchange Between Black Hills Corporation and
Black Hills Holding Corporation (filed as an exhibit
to the Black Hills Holding Corporation's Registration
Statement on Form S-4 (No. 333-52664)).
3.1* Restated Articles of Incorporation of the Registrant
(filed as an exhibit to the Registrant's Form 8-K
dated June 7, 1994 (No. 1-7978)).
3.2 Articles of Amendment to the Articles of
Incorporation of the Registrant, as filed with the
Secretary of State of the State of South Dakota on
December 22, 2000.
3.3* Bylaws of the Registrant (filed as an exhibit to the
Registrant's Registration Statement on Form S-8 dated
July 13, 1999).
4.1* Restated and Amended Indenture of Mortgage and Deed
of Trust of Black Hills Corporation (now called Black
Hills Power, Inc.) dated as of September 1, 1999
(filed as an exhibit to Black Hills Holding
Corporation's Registration Statement on Form S-4 (No.
333-52664)).
10.1* Agreement for Transmission Service and the Common Use
of Transmission Systems dated January 1, 1986, among
Black Hills Power, Inc., Basin Electric Power
Cooperative, Rushmore Electric Power Cooperative,
Inc., Tri-County Electric Association, Inc., Black
Hills Electric Cooperative, Inc. and Butte Electric
Cooperative, Inc. (filed as Exhibit 10(d) to the
Registrant's Form 10-K for 1987).
10.2* Restated and Amended Coal Supply Agreement for NS II
dated February 12, 1993 (filed as Exhibit 10(c) to
the Registrant's Form 10-K for 1992).
10.3* Coal Leases between Wyodak Resources Development
Corp. and the Federal Government
-Dated May 1, 1959 (filed as Exhibit 5(i) to the
Registrant's Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit
10(h) to the Registrant's Form 10-K for 1989)
-Dated April 1, 1961 (filed as Exhibit 5(j) to the
Registrant's Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit
10(i) to Registrant's Form 10-K for 1989)
-Dated October 1, 1965 (filed as Exhibit 5(k) to the
Registrant's Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit
10(j) to the Registrant's Form 10-K for 1989).
10.4* Further Restated and Amended Coal Supply Agreement
dated May 5, 1987 between Wyodak Resources Development
Corp. and Pacific Power & Light Company (filed as
Exhibit 10(k) to the Registrant's Form 10-K for 1987).
10.5* Second Restated and Amended Power Sales Agreement
dated September 29, 1997, between PacifiCorp and
Black Hills Power, Inc. (filed as Exhibit 10(e) to
the Registrant's Form 10-K for 1997).
10.6* Coal Supply Agreement for Wyodak Unit #2 dated
February 3, 1983, and Ancillary Agreement dated
February 3, 1982, between Wyodak Resources
Development Corp., Pacific Power & Light Company and
Black Hills Power, Inc. (filed as Exhibit 10(o) to
the Registrant's Form 10-K for 1983). Amendment to
Agreement for Coal Supply for Wyodak #2 dated May 5,
1987 (filed as Exhibit 10(o) to the Registrant's Form
10-K for 1987).
10.7* Reserve Capacity Integration Agreement dated May 5,
1987, between Pacific Power & Light Company and Black
Hills Power, Inc. (filed as Exhibit 10(u) to the
Registrant's Form 10-K for 1987).
10.8* Marketing, Capacity and Storage Service Agreement
between Black Hills Power, Inc. and PacifiCorp dated
September 1, 1995 (filed as Exhibit 10(ag) to the
Registrant's Form 10-K for 1995).
10.9* Assignment of Mining Leases and Related Agreement
effective May 27, 1997, between Wyodak Resources
Development Corp. and Kerr-McGee Coal Corporation
(filed as Exhibit 10(u) to the Registrant's Form 10-K
for 1997).
10.10* Rate Freeze Extension (filed as Exhibit 10(t) to the
Registrant's Form 10-K for 1999).
10.11*+ Amended and Restated Pension Equalization Plan of
Black Hills Corporation dated January 6, 2000 (filed
as Exhibit 10.11 to Black Hills Corporation's
Form 10-K for 2000).
10.12*+ First Amendment to the Pension Equalization Plan of
Black Hills Corporation dated January 30, 2001 (filed
as Exhibit 10.12 to Black Hills Corporation's Form
10-K for 2000).
. 10.13*+ Black Hills Corporation Nonqualified Deferred
Compensation Plan dated June 1, 1999 (filed as
Exhibit 10.13 to Black Hills Corporation's Form 10-K
for 2000).
10.14*+ Black Hills Corporation 1999 Stock Option Plan (filed
as Exhibit 10.14 to Black Hills Corporation's Form
10-K for 2000).
10.15*+ Agreement for Supplemental Pension Benefit for
Everett E. Hoyt dated January 20, 1992 (filed as
Exhibit 10(gg) to the Registrant's Form 10-K for
1992).
10.16*+ Change in Control Agreements for various officers
(filed as Exhibit 10(af) to the Registrant's
Form 10-K for 1995).
10.17*+ Black Hills Corporation 1996 Stock Option Plan (filed
as Exhibit 10(s) to the Registrant's Form 10-K for
1997).
10.18*+ Outside Directors Stock Based Compensation Plan
(filed as Exhibit 10(t) to the Registrant's Form 10-K
for 1997).
10.19*+ Officers Short-Term Incentive Plan (filed as Exhibit
10(s) to the Registrant's Form 10-K for 1999).
10.20* Agreement and Plan of Merger, dated as of January 1,
2000, among Black Hills Corporation, Black Hills
Energy Capital, Inc., Indeck Capital, Inc., Gerald R.
Forsythe, Michelle R. Fawcett, Marsha Fournier,
Monica Breslow, Melissa S. Forsythe and John W.
Salyer, Jr. (Exhibit 2 to Schedule 13D filed on
behalf of the former shareholders of Indeck Capital,
Inc. consisting of Gerald R. Forsythe, Michelle R.
Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
Forsythe and John W. Salyer, Jr., dated July 7, 2000)
10.21* Addendum to the Agreement and Plan of Merger, dated
as of April 6, 2000, among Black Hills Corporation,
Black Hills Energy Capital, Inc., Indeck Capital,
Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha
Fournier, Monica Breslow, Melissa S. Forsythe and
John W. Salyer, Jr. (Exhibit 3 to Schedule 13D filed
on behalf of the former shareholders of Indeck
Capital, Inc. consisting of Gerald R. Forsythe,
Michelle R. Fawcett, Marsha Fournier, Monica Breslow,
Melissa S. Forsythe and John W. Salyer, Jr., dated
July 7, 2000).
10.22* Supplemental Agreement Regarding Contingent Merger
Consideration, dated as of January 1, 2000, among
Black Hills Corporation, Black Hills Energy Capital,
Inc., Indeck Capital, Inc., Gerald R. Forsythe,
Michelle R. Fawcett, Marsha Fournier, Monica Breslow,
Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit
4 to Schedule 13D filed on behalf of the former
shareholders of Indeck Capital, Inc. consisting of
Gerald R. Forsythe, Michelle R. Fawcett, Marsha
Fournier, Monica Breslow, Melissa S. Forsythe and
John W. Salyer, Jr., dated July 7, 2000).
10.23* Supplemental Agreement Regarding Restructuring of
Certain Qualifying Facilities (Exhibit 5 to Schedule
13D filed on behalf of the former shareholders of
Indeck Capital, Inc. consisting of Gerald R.
Forsythe, Michelle R. Fawcett, Marsha Fournier,
Monica Breslow, Melissa S. Forsythe and John W.
Salyer, Jr., dated July 7, 2000).
10.24* Addendum to the Agreement and Plan of Merger, dated
as of June 30, 2000, among Black Hills Corporation,
Black Hills Energy Capital, Inc., Indeck Capital,
Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha
Fournier, Monica Breslow, Melissa S. Forsythe and
John W. Salyer, Jr. (Exhibit 6 to Schedule 13D filed
on behalf of the former shareholders of Indeck
Capital, Inc. consisting of Gerald R. Forsythe,
Michelle R. Fawcett, Marsha Fournier, Monica Breslow,
Melissa S. Forsythe and John W. Salyer, Jr., dated
July 7, 2000).
- ----------
* Previously filed as part of the filing indicated and incorporated by
reference herein.
+ Indicates a board of director or management compensatory plan.
(b) Reports on Form 8-K
We have filed the following Reports on Form 8-K since September 30,
2000.
Form 8-K filed December 22, 2000.
Reported the formation of the holding company structure through a
"Plan of Exchange" between Black Hills Corporation and Black
Hills Holding Corporation on December 22, 2000.
(c) See (a) 3. Exhibits above.
(d) See (a) 2. Schedules above.
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT.
The Registrant is not required to send an Annual Report or Proxy to its sole
security holder and parent company, Black Hills Corporation.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BLACK HILLS POWER, INC.
By DANIEL P. LANDGUTH
Daniel P. Landguth, Chairman
and Chief Executive Officer
Dated: March 30, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
DANIEL P. LANDGUTH Director and Principal March 30, 2001
- --------------------------------------------- Executive Officer
Daniel P. Landguth, Chairman,
and Chief Executive Officer
MARK T. THIES Principal Financial Officer March 30, 2001
- ---------------------------------------------
Mark T. Thies, Senior Vice President and
Chief Financial Officer
ROXANN R. BASHAM Principal Accounting Officer March 30, 2001
- ---------------------------------------------
Roxann R. Basham, Vice President-Controller,
and Assistant Secretary
ADIL M. AMEER Director March 30, 2001
- ---------------------------------------------
Adil M. Ameer
BRUCE B. BRUNDAGE Director March 30, 2001
- ---------------------------------------------
Bruce B. Brundage
DAVID C. EBERTZ Director March 30, 2001
- ---------------------------------------------
David C. Ebertz
GERALD R. FORSYTHE Director March 30, 2001
- ---------------------------------------------
Gerald R. Forsythe
JOHN R. HOWARD Director March 30, 2001
- ---------------------------------------------
John R. Howard
EVERETT E. HOYT Director and Officer March 30, 2001
- ---------------------------------------------
Everett E. Hoyt, President and Chief
Operating Officer
KAY S. JORGENSEN Director March 30, 2001
- ---------------------------------------------
Kay S. Jorgensen
DAVID S. MANEY Director March 30, 2001
- ---------------------------------------------
David S. Maney
THOMAS J. ZELLER Director March 30, 2001
- ---------------------------------------------
Thomas J. Zeller
INDEX TO EXHIBITS
Exhibit
Number Description
2* Plan of Exchange Between Black Hills Corporation and Black
Hills Holding Corporation (filed as an exhibit to the
Black Hills Holding Corporation's Registration Statement
on Form S-4 (No. 333-52664)).
3.1* Restated Articles of Incorporation of the Registrant
(filed as an exhibit to the Registrant's Form 8-K dated
June 7, 1994 (No. 1-7978)).
3.2 Articles of Amendment to the Articles of Incorporation of
the Registrant, as filed with the Secretary of State
of the State of South Dakota on December 22, 2000.
3.3* Bylaws of the Registrant (filed as an exhibit to the
Registrant's Registration Statement on Form S-8 dated July
13, 1999).
4.1* Restated and Amended Indenture of Mortgage and Deed of
Trust of Black Hills Corporation (now called Black Hills
Power, Inc.) dated as of September 1, 1999 (filed as an
exhibit to the Registrant's Registration Statement on Form
S-4 (No. 333-52664)).
10.1* Agreement for Transmission Service and the Common Use of
Transmission Systems dated January 1, 1986, among Black
Hills Power, Inc., Basin Electric Power Cooperative,
Rushmore Electric Power Cooperative, Inc., Tri-County
Electric Association, Inc., Black Hills Electric
Cooperative, Inc. and Butte Electric Cooperative, Inc.
(filed as Exhibit 10(d) to the Registrant's Form 10-K for
1987).
10.2* Restated and Amended Coal Supply Agreement for NS II dated
February 12, 1993 (filed as Exhibit 10(c) to the
Registrant's Form 10-K for 1992).
10.3* Coal Leases between Wyodak Resources Development Corp. and
the Federal Government
-Dated May 1, 1959 (filed as Exhibit 5(i) to the
Registrant's Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(h)
to the Registrant's Form 10-K for 1989)
-Dated April 1, 1961 (filed as Exhibit 5(j) to the
Registrant's Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(i)
to Registrant's Form 10-K for 1989)
-Dated October 1, 1965 (filed as Exhibit 5(k) to the
Registrant's Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(j)
to the Registrant's Form 10-K for 1989).
10.4* Further Restated and Amended Coal Supply Agreement dated
May 5, 1987 between Wyodak Resources Development Corp. and
Pacific Power & Light Company (filed as Exhibit 10(k) to
the Registrant's Form 10-K for 1987).
10.5* Second Restated and Amended Power Sales Agreement dated
September 29, 1997, between PacifiCorp and Black Hills
Power, Inc. (filed as Exhibit 10(e) to the Registrant's
Form 10-K for 1997).
10.6* Coal Supply Agreement for Wyodak Unit #2 dated February 3,
1983, and Ancillary Agreement dated February 3, 1982,
between Wyodak Resources Development Corp., Pacific Power
& Light Company and Black Hills Power, Inc. (filed as
Exhibit 10(o) to the Registrant's Form 10-K for 1983).
Amendment to Agreement for Coal Supply for Wyodak #2 dated
May 5, 1987 (filed as Exhibit 10(o) to the Registrant's
Form 10-K for 1987).
10.7* Reserve Capacity Integration Agreement dated May 5, 1987,
between Pacific Power & Light Company and Black Hills
Power, Inc. (filed as Exhibit 10(u) to the Registrant's
Form 10-K for 1987).
10.8* Marketing, Capacity and Storage Service Agreement between
Black Hills Power, Inc. and PacifiCorp dated September 1,
1995 (filed as Exhibit 10(ag) to the Registrant's
Form 10-K for 1995).
10.9* Assignment of Mining Leases and Related Agreement
effective May 27, 1997, between Wyodak Resources
Development Corp. and Kerr-McGee Coal Corporation (filed
as Exhibit 10(u) to the Registrant's Form 10-K for 1997).
10.10* Rate Freeze Extension (filed as Exhibit 10(t) to the
Registrant's Form 10-K for 1999).
10.11*+ Amended and Restated Pension Equalization Plan of Black
Hills Corporation dated January 6, 2000 (filed as Exhibit
10.11 to Black Hills Corporation's Form 10-K for 2000).
10.12*+ First Amendment to the Pension Equalization Plan of Black
Hills Corporation dated January 30, 2001 (filed as Exhibit
10.12 to Black Hills Corporation's Form 10-K for 2000).
10.13*+ Black Hills Corporation Nonqualified Deferred Compensation
Plan dated June 1, 1999 (filed as Exhibit 10.13 to Black
Hills Corporation's Form 10-K for 2000).
10.14*+ Black Hills Corporation 1999 Stock Option Plan (filed
as Exhibit 10.14 to Black Hills Corporation's Form 10-K
for 2000).
10.15*+ Agreement for Supplemental Pension Benefit for Everett E.
Hoyt dated January 20, 1992 (filed as Exhibit 10(gg) to
the Registrant's Form 10-K for 1992).
10.16*+ Change in Control Agreements for various officers (filed
as Exhibit 10(af) to the Registrant's Form 10-K for 1995).
10.17*+ Black Hills Corporation 1996 Stock Option Plan (filed as
Exhibit 10(s) to the Registrant's Form 10-K for 1997).
10.18*+ Outside Directors Stock Based Compensation Plan (filed as
Exhibit 10(t) to the Registrant's Form 10-K for 1997).
10.19*+ Officers Short-Term Incentive Plan (filed as Exhibit 10(s)
to the Registrant's Form 10-K for 1999).
10.20* Agreement and Plan of Merger, dated as of January 1, 2000,
among Black Hills Corporation, Black Hills Energy Capital,
Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R
Fawcett, Marsha Fournier, Moncia Breslow, Melissa S.
Forsythe and John W. Salyer, Jr. (Exhibit 2 to Schedule
13D filed on behalf of the former shareholders of Indeck
Capital, Inc. consisting of Gerald R. Forsythe, Michelle R
Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.21* Addendum to the Agreement and Plan of Merger, dated as of
April 6, 2000, among Black Hills Corporation, Black Hills
Energy Capital, Inc., Indeck Capital, Inc., Gerald R.
Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica
Breslow, Melissa S. Forsythe and John W. Salyer, Jr.
(Exhibit 3 to Schedule 13D filed on behalf of the former
shareholders of Indeck Capital, Inc. consisting of Gerald
R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica
Breslow, Melissa S. Forsythe and John W. Salyer, Jr.,
dated July 7, 2000).
10.22* Supplemental Agreement Regarding Contingent Merger
Consideration, dated as of January 1, 2000, among Black
Hills Corporation, Black Hills Energy Capital, Inc.,
Indeck Capital, Inc., Gerald R. Forsythe, Michelle R.
Fawcett, Marsha Fournier, Moncia Breslow, Melissa S.
Forsythe and John W. Salyer, Jr. (Exhibit 4 to Schedule
13D filed on behalf of the former shareholders of Indeck
Capital, Inc. consisting of Gerald R. Forsythe, Michelle
R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
Forsythe and John W. Salyer, Jr., dated July 7, 2000).
10.23* Supplemental Agreement Regarding Restructuring of Certain
Qualifying Facilities (Exhibit 5 to Schedule 13D filed on
behalf of the former shareholders of Indeck Capital, Inc.
consisting of Gerald R. Forsythe, Michelle R. Fawcett,
Marsha Fournier, Monica Breslow, Melissa S. Forsythe and
John W. Salyer, Jr., dated July 7, 2000).
10.24* Addendum to the Agreement and Plan of Merger, dated as of
June 30, 2000, among Black Hills Corporation, Black Hills
Energy Capital, Inc., Indeck Capital, Inc., Gerald R.
Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica
Breslow, Melissa S. Forsythe and John W. Salyer, Jr.
(Exhibit 6 to Schedule 13D filed on behalf of the former
shareholders of Indeck Capital, Inc. consisting of Gerald
R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica
Breslow, Melissa S. Forsythe and John W. Salyer, Jr.,
dated July 7, 2000).
- ----------
* Previously filed as part of the filing indicated and incorporated by
reference herein.
+ Indicates a board of director or management compensatory plan.